Management’s Discussion and Analysis For the three and sixsixsix months ended June 30, 202010101010

Forward Looking Information The following Management Discussion and Analysis (MD&A) highlights significant business results and statistics for Inter Pipeline Fund’s (Inter Pipeline) three and six month periods ended June 30, 2010. This MD&A contains certain forward-looking statements or information (collectively referred to as “forward- looking statements”) within the meaning of applicable securities legislation. Forward-looking statements often contain terms such as "may", "will", "should", "anticipate", "expect", “continue”, “estimate”, “believe”, “project”, and similar words suggesting future outcomes or statements regarding an outlook. Any statements herein that are not statements of historical fact may be deemed to be forward-looking statements. Forward-looking statements in this MD&A include, but are not limited to statements regarding: 1) Inter Pipeline’s beliefs that it is well positioned to maintain its current level of cash distributions to its unitholders through 2011 and beyond; 2) the maintenance of Inter Pipeline's cash distribution level combined with the tax treatment of distributions to its unitholders effective in 2011 should result in a favourable after-tax treatment for Inter Pipeline's taxable unitholders; 3) Inter Pipeline being well positioned to operate and grow in the future; and, 4) cash flow projections, timing for completion of its Corridor pipeline expansion project, the Polaris diluent pipeline project for the Kearl oil sands mining project (Kearl project), new Cold Lake pipeline expansion for the Foster Creek oil sands project (Foster Creek project), Cochrane desulphurization facility and other capital forecasts.

Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the expectations, plans or intentions upon which they are based will occur. Inter Pipeline in no manner represents that actual results achieved will be the same in whole or in part as those set out in the forward-looking statements herein. Such information, although considered reasonable by Pipeline Management Inc., the general partner of Inter Pipeline (General Partner) at the time of preparation, may later prove to be incorrect and actual results may differ materially from those anticipated in the forward- looking statements. By their nature, forward-looking statements are subject to various risks, uncertainties and other factors, which are beyond Inter Pipeline’s control, including, but not limited to: risks associated with operations, such as Inter Pipeline’s ability to successfully implement its strategic initiatives and achieve expected benefits; the status, credit risk and continued existence of customers having contracts with Inter Pipeline and its subsidiaries; availability of energy commodities; volatility of and assumptions regarding prices of energy commodities; competitive factors, pricing pressures and supply and demand in the natural gas and oil transportation, ethane transportation and natural gas liquids (NGL) extraction and storage industries; assumptions based upon Inter Pipeline’s current guidance; fluctuations in currency and interest rates; the ability to access sufficient capital from internal and external sources; product supply and demand; risks inherent in Inter Pipeline’s Canadian and foreign operations; risks of war, hostilities, civil insurrection and instability affecting countries in which Inter Pipeline and its subsidiaries operate; severe weather conditions; terrorist threats; risks associated with technology; Inter Pipeline’s ability to generate sufficient cash flow from operations to meet its current and future obligations; Inter Pipeline’s ability to access external sources of debt and equity capital; general economic and business conditions; potential delays and cost overruns on construction projects, including, but not limited to the Corridor and other projects noted above; Inter Pipeline’s ability to make capital investments and amount of capital investments; changes in laws and regulations, including environmental, regulatory and taxation laws, and the interpretation of such changes to laws and regulations; the risks associated with existing and potential future lawsuits and regulatory actions against Inter Pipeline and its subsidiaries; increases in maintenance, operating or financing costs; availability of adequate levels of insurance; political and economic conditions in the countries in which Inter Pipeline and its subsidiaries operate; difficulty in obtaining necessary regulatory approvals; and such other risks and uncertainties described from time to time in Inter Pipeline’s reports and filings with the Canadian securities authorities.

Readers are cautioned that the foregoforegoinging list of importantimportant factors is not exhaustive. SeSeee also the sectionsection entitled RISK FACTORS included in Inter Pipeline’s MD&A for the year ended December 3131,,,, 2009. The forwardforward----lookinglooking statements contained in this MD&A are made as of the date of this document,docume nt, and, except to the extent expressly required by applicable securities laws and regulations, Inter Pipeline assumes no obligation to update or revise forwardforward----lookinglooking statements made herein or otherwise, whether as a result of new information, future eveevennts,ts, or otherwise. The forwardforward----lookinglooking statements contained in this document are expressly qualified by this cautionary note.

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Management’s Discussion and Analysis For the three and six month periods ended June 30, 2010

The MD&A provides a detailed explanation of Inter Pipeline’s operating results for the three and six month periods ended June 30, 2010 as compared to the three and six month periods ended June 30, 2009. The MD&A should be read in conjunction with the MD&A for the quarterly period ended March 31, 2010, the unaudited interim consolidated financial statements of Inter Pipeline for the quarterly periods ended March 31 and June 30, 2010, the audited consolidated financial statements and MD&A for the year ended December 31, 2009, the Annual Information Form and other information filed by Inter Pipeline at www.sedar.com .

Financial information presented in this MD&A is based on information in Inter Pipeline’s consolidated financial statements prepared in accordance with Canadian generally accepted accounting principles (GAAP). This MD&A reports certain non-GAAP financial measures that are used by management to evaluate the performance of Inter Pipeline and its business segments. Since certain non-GAAP financial measures may not have a standardized meaning, securities regulations require that non-GAAP financial measures are clearly defined, qualified and reconciled with their nearest GAAP measure. See the NON- GAAP FINANCIAL MEASURES section for further information on the definition, calculation and reconciliation of non-GAAP financial measures. All amounts are in Canadian dollars unless specified otherwise.

Management considers if information presented in this MD&A is material based on whether it believes a reasonable investor’s decision to buy, sell or hold securities in Inter Pipeline would likely be influenced or changed if the information was omitted or misstated.

Page SECOND QUARTER HIGHLIGHTS ...... 4 SUBSEQUENT EVENTS...... 4 PERFORMANCE OVERVIEW...... 5 OUTLOOK...... 7 RESULTS OF OPERATIONS ...... 9 SUMMARY OF QUARTERLY RESULTS ...... 19 LIQUIDITY AND CAPITAL RESOURCES ...... 20 CASH DISTRIBUTIONS TO UNITHOLDERS...... 24 OUTSTANDING UNIT DATA...... 26 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS...... 26 TRANSACTIONS WITH RELATED PARTIES ...... 30 CONTROLS AND PROCEDURES ...... 31 CRITICAL ACCOUNTING ESTIMATES...... 31 CHANGES IN ACCOUNTING POLICIES ...... 31 RISK FACTORS ...... 35 NON-GAAP FINANCIAL MEASURES ...... 35 ELIGIBLE INVESTORS ...... 37 ADDITIONAL INFORMATION ...... 37 CONSOLIDATED FINANCIAL STATEMENTS...... 38

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SECOND QUARTER HIGHLIGHTS

• Funds from operations* increased to $88.3 million in the second quarter

• Attractive payout ratio before sustaining capital* of 65.4%

• Cash distributions to unitholders totalled $57.8 million, or $0.225 per unit

• Generated net income of $67.9 million or $0.27 per unit, an increase of 73% over the second quarter of 2009.

• Throughput volumes on Inter Pipeline’s oil sands and conventional oil pipeline systems averaged 735,500 barrels per day (b/d) in the second quarter

• Record volumes transported on the Cold Lake pipeline system, averaging 455,100 b/d in the quarter

SUBSEQUENT EVENTS

• Announced a $40 million expansion project on the Cold Lake pipeline system to increase transportation capacity for the Foster Creek oil sands project

• DBRS Limited (DBRS) upgraded Inter Pipeline’s credit rating from BBB to BBB (high) for Inter Pipeline and Inter Pipeline (Corridor) Inc.’s long-term credit rating from A (low) to A

*Please refer to the NON-GAAP FINANCIAL MEASURES section

4 PERFORMANCE OVERVIEW Three Months Ended Six Months Ended June 30 June 30 (millions, except per unit and % amounts) 2010 2009 2010 2009 Revenues Oil sands transportation $ 36.4 $ 30.6 $ 71.3 $ 64.3 NGL extraction 143.4 98.1 316.5 241.3 Conventional oil pipelines 37.7 39.8 75.3 78.4 Bulk liquid storage 23.9 28.8 49.9 58.9 $ 241.4 $ 197.3 $ 513.0 $ 442.9

Funds from operations (1)(2) Oil sands transportation $ 18.9 $ 17.9 $ 37.5 $ 36.0 NGL extraction 42.2 25.2 89.9 51.3 Conventional oil pipelines 27.7 31.8 55.8 60.4 Bulk liquid storage 15.3 9.9 25.5 20.3 Corporate costs (15.8) (16.3) (35.0) (33.4) $ 88.3 $ 68.5 $ 173.7 $ 134.6 Per unit (1)(2) $ 0.34 $ 0.30 $ 0.68 $ 0.60

Net income $ 67.9 $ 39.3 $ 129.6 $ 82.7 Per unit – basic and diluted $ 0.27 $ 0.18 $ 0.51 $ 0.37

Cash distributions (3) $ 57.8 $ 48.6 $ 115.4 $ 95.5 Per unit (3) $ 0.225 $ 0.210 $ 0.450 $ 0.420

Units outstanding (basic) Weighted average 256.6 227.0 256.2 225.2 End of period 256.9 246.5 256.9 246.5

Capital expenditures Growth (2) $ 34.2 $ 46.0 $ 65.4 $ 103.0 Sustaining (2) 5.6 3.6 8.1 6.6 $ 39.8 $ 49.6 $ 73.5 $ 109.6

Payout ratio before sustaining capital (2) 65.4% 71.0% 66.4% 71.0% Payout ratio after sustaining capital (2) 69.9% 75.0% 69.7% 74.6%

June 30 December 31 2010 2009 Total assets $ 4,480.3 $ 4,472.7 Total debt (4) $ 2,585.4 $ 2,619.7 Total partners’ equity $ 1,334.2 $ 1,320.1 Enterprise value (2) $ 5,655.7 $ 5,372.4 Total debt to total capitalization (2) 66.0% 66.5% (2) Total recourse debt to capitalization 34.3% 35.7%

(1) In the second quarter of 2010, funds from operations for the bulk liquid storage business increased by $5.8 million due to cash proceeds received for customer storage fees paid in advance. (2) Please refer to the NON-GAAP FINANCIAL MEASURES section of this MD&A. (3) Cash distributions are calculated based on the number of units outstanding at each record date. (4) Total debt reported in the June 30, 2010 consolidated financial statements include long-term debt of $2,576.6 million inclusive of discounts and debt transaction costs of $8.8 million.

5 THREE MONTHS ENDED JUNE 30, 2010 Inter Pipeline generated solid financial results in the second quarter of 2010 primarily driven by favourable commodity prices and volumes in the NGL extraction business. Funds from operations of $88.3 million were $19.8 million or 28.9% higher than the $68.5 million generated in 2009 resulting in an attractive payout ratio before sustaining capital of 65.4%. Operating results for the oil sands transportation business were also higher due to additional revenue from the record volumes transported on the Cold Lake pipeline system during the quarter, while funds from operations for the bulk liquid storage business were higher than in 2009 due to timing of cash receipts. Somewhat offsetting these strong results were lower operating results for the conventional oil pipelines business due to a decline in midstream marketing revenue.

Net income of $67.9 million in the second quarter of 2010 was $28.6 million or 72.8% higher than the $39.3 million earned in the same period in 2009. In addition to the strong financial results generated by the NGL extraction business, net income benefited from a favourable $13.3 million unrealized change in the mark-to-market value of derivative financial instruments outstanding at June 30, 2010, as compared to an unfavourable change of $19.6 million in the second quarter of 2009. A gain of $20.9 million on the sale of the Valley pipeline system in 2009 also impacted the net income variance.

Total cash distributed to unitholders in the second quarter of 2010 increased $9.2 million or 18.9% to $57.8 million compared to $48.6 million distributed in the second quarter of 2009. This increase in cash distributions was the result of both a higher number of units outstanding during the second quarter of 2010 and a 7.1% per unit increase in monthly cash distributions to $0.075 per unit effective December 2009. The majority of new units were issued pursuant to a successful public unit offering in June 2009 and new distribution reinvestment plan adopted in May 2009.

Inter Pipeline’s total debt increased $8.6 million during the quarter from $2,576.8 million at March 31, 2010 to $2,585.4 million, while $39.8 million was invested in capital projects. Inter Pipeline’s recourse debt to capitalization ratio decreased slightly from 34.4% at March 31, 2010 to 34.3% at June 30, 2010.

SIX MONTHS ENDED JUNE 30, 2010 Strong financial performance in the first half of 2010 resulted in increased funds from operations of $173.7 million, which is $39.1 million or 29.0% higher than the $134.6 million generated in 2009. The primary driver of the increase was strong financial results in the NGL extraction business due to increased volumes and higher realized frac-spread prices from propane-plus sales at the Cochrane NGL extraction facility. Operating results generated by the oil sands transportation and bulk liquid storage businesses were also higher mainly due to increased volumes transported on the Cold Lake pipeline system and timing of cash receipts, respectively. These increases were partially offset by lower funds from operations from the conventional oil pipelines business segment. Inter Pipeline generated a strong payout ratio before sustaining capital of 66.4% for the first half of 2010.

Net income of $129.6 million in the first six months of 2010 was $46.9 million higher than the $82.7 million earned in the same period in 2009. This increase was primarily due to strong results from the NGL extraction business noted above and favourable unrealized changes in the fair value of derivative financial instruments of $20.4 million in 2010 as compared to an unfavourable change in 2009 of $41.0 million. Inter Pipeline also recognized a $20.9 million gain on the sale of the Valley pipeline system in April 2009 and a $24.0 million reduction in accrued future income taxes related to changes in provincial SIFT tax rates legislated in March 2009.

Total cash distributed to unitholders in the six months ended June 30, 2010 increased $19.9 million or 20.8% to $115.4 million compared to $95.5 million distributed in the same period in 2009. This was a result of additional units issued pursuant to an equity offering in June 2009, new distribution reinvestment plan and increased monthly cash distributions as discussed above.

Since December 2009, consolidated debt decreased $34.3 million to $2,585.4 million at June 30, 2010, while Inter Pipeline invested approximately $65.4 million on growth capital projects during this period.

6 Undistributed funds from operations were utilized to reduce indebtedness on Inter Pipeline’s $750 million revolving credit facility. Inter Pipeline’s recourse debt to capitalization ratio decreased from 35.7% at December 31, 2009 to 34.3% at June 30, 2010. Adjusting for the inclusion of non-recourse debt of $1,887.8 million held within the Corridor corporate entity, Inter Pipeline’s total debt to total capitalization ratio was 66.0%

OUTLOOK Inter Pipeline’s business strategy is to develop long-life, high quality energy infrastructure assets that provide sustainable and predictable cash flows over the long term. Activity in the current year is consistent with this objective. Major projects continue to develop while new organic growth projects are being initiated to enhance the predictability and sustainability of future cash flows. As work on the $1.8 billion Corridor pipeline capacity expansion project nears completion, efforts remain focused on the final phases of the expansion. When in commercial service, cash flow contributions from this project will provide substantial support for Inter Pipeline’s goal of maintaining cash distributions to unitholders at current levels through 2011 and beyond. Further opportunities developed utilizing existing infrastructure such as the Polaris diluent transportation system described below are a key component of Inter Pipeline’s future growth.

The Corridor expansion project is nearing completion on schedule and on budget.... When in service, bitumen blend transport capacity on the Corridor system is expected to initially increase from 300,000 b/d to 465,000 b/d. This additional capacity will accommodate shipments of increased oil sands production from the Athabasca Oil Sands Project, a joint venture between Shell Canada Limited, Chevron Canada and Marathon Oil Canada Corporation. Cost-of-service type contractual arrangements that govern the original Corridor pipeline system will also apply to this expansion, contributing to stable long-term cash flows. The new 42-inch diameter line has now been successfully commissioned, with final line fill activities on this segment completed in the second quarter. Remaining commissioning activity is primarily related to a 43 kilometre products line that will continue into late 2010. Incremental revenue from the expansion will commence no later than January 1, 2011.

As previously announced, a 25-year agreement to transport diluent for the Kearl project will anchor initial development of the Polaris pipeline system. The Kearl project is owned by Imperial Oil Resources Ventures Limited, a jointly owned venture between Imperial Oil Limited and ExxonMobil Canada. In the second quarter of 2010, detailed engineering work continued on the project, and long-lead items are being procured in order to meet the estimated 2012 start up date. Diluent volumes to be transported for the Kearl project under this agreement are contracted at 60,000 b/d, or half of the system’s 120,000 b/d nominal capacity. Inter Pipeline is pursuing further opportunities to utilize the remaining capacity on the Polaris system and anticipates transporting additional diluent volumes to either the Kearl project, or other oil sands production sites.

Announced subsequent to quarter end was a $40 million project to install 27 kilometres of pipeline on the Cold Lake system that will increase pipeline capacity available for the Foster Creek project. Foster Creek is a major in-situ bitumen recovery project owned by Cenovus Energy Inc. and ConocoPhillips Canada Resources Corporation under a 50/50 joint partnership. The new pipeline will parallel an existing Cold Lake line north of the La Corey terminal and will position the Cold Lake system to meet near and longer term production targets from the Foster Creek project. This investment is another key element of the phased development of the Cold Lake system. It accommodates near term production growth of an existing shipper while building strategic infrastructure consistent with Inter Pipeline’s plans to extend the Cold Lake system further north over the long term. Incremental annual EBITDA of $4.5 million (85% share) is expected to be generated under this agreement once the project is in-service. Construction is planned to start in the third quarter of 2010, with an in-service date of early 2011.

Propane-plus frac-spreads continued to show strength in the second quarter of 2010. High frac-spreads contributed positively to second quarter 2010 financial results, specifically in the NGL extraction business segment. While strong commodity prices significantly benefit overall financial performance through high frac-spreads, Inter Pipeline’s diversified cash flow streams limit the impact of weaker

7 commodity prices to primarily one revenue stream, the sale of propane-plus extracted at the Cochrane NGL extraction facility.

Inter Pipeline continues to be in a very positive financial and commercial position. Inter Pipeline’s balance sheet remains very strong with a total recourse debt to capitalization ratio of just 34.3% at June 30, 2010. Also supporting this positive position is the long-term nature of contracts governing much of Inter Pipeline’s cash flows. A significant portion of these cash flows are cost-of-service type contracts not subject to commodity price or volume risk, particularly in Inter Pipeline’s oil sands transportation business segment. Cash flows supported by cost-of-service contracts are expected to become more predominant in future years as the Corridor expansion and Polaris pipeline system begin generating cash flow .

As of January 1, 2011, publicly-traded flow-through entities such as income trusts and limited partnerships will become subject to taxation. Presently many organizations in this segment are implementing changes to the corporate structure and re-evaluating the sustainability of current cash distribution levels as they become taxable entities.

In order to evaluate the implications of the change in taxable status effective for 2011, the governance committee and the remaining independent directors of Inter Pipeline’s board of directors engaged in a formal process to consider if an alternative business structure, such as converting to a corporation, would be beneficial. In evaluating alternative structures, consideration was given to possible impacts on Inter Pipeline including the level of income taxes to be paid, corporate conversion costs, counterparty consent issues and sustainability of distributions. The review of these impacts by the governance committee and the other independent directors did not reveal any material tangible benefit to Inter Pipeline’s unitholders should it change its existing business structure. As a result, Inter Pipeline’s board of directors determined that Inter Pipeline will remain structured as a publicly traded limited partnership into the foreseeable future. The board of directors will continue to monitor future events which could affect this decision.

Inter Pipeline has stated in past quarters that it is well positioned to maintain its current level of cash distributions to unitholders despite becoming fully taxable in 2011. This outlook remains unchanged. Strong fundamentals within each of Inter Pipeline’s four business segments clearly support cash distributions at current levels, as do expected cash flow increases from organic growth projects currently underway.

The change to a taxable entity will also lead to a more favourable tax treatment of Inter Pipeline’s cash distributions in the hands of a taxable investor. In 2011, these distributions will be treated for tax purposes substantially similar to dividends from Canadian public corporations. This dividend treatment, when combined with Inter Pipeline’s intent to maintain stable cash distributions at current levels through 2011 and beyond, should result in a taxable Canadian investor receiving a favourable after-tax return from owning Inter Pipeline units.

Inter Pipeline’s fully committed credit facilities continue to support a strong financial position. Central to Inter Pipeline’s credit capacity are two well-diversified facilities that are used to operate the business and finance various projects. With approximately $986.4 million in unutilized credit capacity and terms extending into 2012, these facilities provide Inter Pipeline with a solid financial base to support and grow the business.

Credit rating agencies acknowledge the strength of Inter Pipeline’s diversified businesses with consistently strong credit ratings. Subsequent to quarter end, DBRS increased Inter Pipeline’s investment grade credit rating to BBB (high) with a stable trend, up from BBB. DBRS also increased the credit rating of Inter Pipeline’s 100% owned subsidiary, Inter Pipeline (Corridor) Inc. to A from A (low). In both instances, DBRS cited as the main factor for the increases continued successful performance on the Corridor expansion project and Inter Pipeline’s strong balance sheet, which should enable Inter Pipeline to fund equity requirements of Corridor when required. Standard & Poor’s (S&P) has also assigned an investment grade, long-term corporate credit rating of BBB to Inter Pipeline. Inter Pipeline’s 100% owned subsidiary, Inter Pipeline (Corridor) Inc. (Corridor), has been assigned investment grade credit ratings of

8 A3 and A- from Moody’s Investor Services (Moody’s) and S&P, respectively. Successful project management, well-run operations, timely infusions of equity capital, and continued strong financial results are all factors supporting continued investment grade credit ratings.

RESULTS OF OPERATIONS OIL SANDS TRANSPORTATION BUSINESS SEGMENT Three Months Ended Six Months Ended June 30 June 30 Volumes (000s b/d) 2010 2009 % change 2010 2009 % change Cold Lake (100% basis) 455.1 358.4 27.0 451.4 372.5 21.2 Corridor 120.0 211.6 (43.3) 153.1 208.8 (26.7) 575.1 570.0 0.9 604.5 581.3 4.0

(millions) Revenue (1) $ 36.4 $ 30.6 19.0 $ 71.3 $ 64.3 10.9 Operating expenses (1) $ 14.3 $ 10.7 33.6 $ 27.6 $ 23.1 19.5 Funds from operations (1)(2) $ 18.9 $ 17.9 5.6 $ 37.5 $ 36.0 4.2 Capital expenditures (1) Growth (2) $ 29.0 $ 27.7 $ 54.6 $ 71.9 Sustaining (2) 0.6 0.1 0.6 0.1 $ 29.6 $ 27.8 $ 55.2 $ 72.0

(1) Cold Lake pipeline system’s revenue, operating expenses, funds from operations and capital expenditures are recorded on the basis of Inter Pipeline’s 85% ownership interest. (2) Please refer to the NON----GAAP FINANCIAL MEASURES section.

Volumes The Cold Lake pipeline system is a bitumen blend and diluent pipeline system that transports diluted bitumen from the Cold Lake area of Alberta to delivery points in the Hardisty and Edmonton areas. Average volume transported on this system increased by 96,700 b/d in the second quarter of 2010 (to a record 455,100 b/d) and 78,900 b/d year to date 2010 compared to the same periods in 2009. Volumes on this system fluctuate mainly due to the timing of steam injection cycles associated with certain shipper production processes. Inter Pipeline expects to continue to see incremental volume growth on the system as supported by the shippers’ long term published forecasts.

The Corridor pipeline system is also a bitumen blend and diluent pipeline system transporting diluted bitumen from the Muskeg River mine near Fort McMurray, Alberta to the Scotford upgrader located northeast of Edmonton, Alberta. Average Corridor volumes decreased 91,600 b/d in the second quarter and 55,700 b/d year to date as compared to the same periods in 2009. The decrease in volume in both periods was due to turnarounds at the Muskeg River mine and Scotford upgrader that occurred during the second quarter. The turnarounds coincided with commissioning activities associated with the Corridor pipeline expansion project, during which approximately 1.5 million barrels in the second quarter and 2.5 million barrels year to date of diluted bitumen were diverted as line fill for the new 42-inch diameter pipeline.

Revenue Oil sands transportation revenue was approximately $5.8 million higher in the second quarter of 2010 and $7.0 million higher year to date 2010 as compared to the same periods in 2009. Cold Lake revenue increased $6.4 million in the second quarter and $8.2 million year to date which was primarily attributable to the increase in volumes shipped and higher power cost recoveries. Corridor revenue was $0.6 million lower in the second quarter and $1.2 million year to date compared to the same periods in 2009.

9 The Cold Lake Transportation Services Agreement (Cold Lake TSA) provides a structured return on capital invested in pipelines and facilities that comprise the Cold Lake pipeline system and recovery of substantially all operating costs over the term of the agreement. The founding shippers’ annual minimum ship-or-pay commitment under the terms of the Cold Lake TSA is $27.8 million to the end of December 2011 based on Inter Pipeline’s 85% ownership interest ($32.7 million – 100% basis). Inter Pipeline receives additional capital fees for volumes shipped over and above the defined ship-or-pay amounts. Certain additional facilities on the Cold Lake pipeline system also produce an additional return on capital invested and recovery of associated operating costs.

The Corridor pipeline system is operated pursuant to a long-term Firm Service Agreement (Corridor FSA). The Corridor FSA utilizes a rate base cost-of-service approach to establish an annual revenue requirement which includes recovery of debt financing costs, all operating costs, rate base depreciation and taxes in addition to providing a return on equity. As a result of this cost-of-service arrangement, Corridor’s funds from operations are not impacted by throughput volumes or commodity price fluctuations. The main drivers of any potential variation in Corridor’s funds from operations are changes to long-term Government of Canada bond rates which are the basis for the annual return on equity, and changes to the underlying rate base.

Corridor’s revenue was $0.6 million lower in the second quarter of 2010 compared to the same period in 2009. Operating cost recoveries decreased approximately $1.8 million due to lower maintenance costs, and fuel and power costs as a result of decreased consumption due to lower volumes. Average blended short-term and long-term interest rates increased approximately 125 basis points which resulted in a $1.4 million increase in debt financing costs and related revenue.

Corridor’s year to date revenue was $1.2 million lower in 2010 compared to 2009. Operating cost recoveries declined approximately $2.0 million due to lower maintenance and power costs. Average blended short-term and long-term interest rates during the first half of 2010 increased approximately 44 basis points compared to the first half of 2009, which resulted in a $0.9 million increase in debt financing costs and related revenue.

Operating Expenses Operating expenses have a limited impact on Inter Pipeline’s cash flow as substantially all expenditures are recovered from the shippers on both the Cold Lake and Corridor pipeline systems.

In the second quarter of 2010, operating expenses increased $3.6 million compared to the same period in 2009, of which $3.5 million was related to increased power costs. An increase in average Alberta power pool prices and increased consumption on the Cold Lake pipeline system related to higher volumes was partially offset by lower consumption on the Corridor pipeline as a result of reduced volumes on that system. Power prices increased 151.2% from $32.30/MWh in the second quarter of 2009 to $81.15/MWh in the same period in 2010. The trend was similar year to date as average published power prices increased from $47.74/MWh in 2009 to $61.08/MWh in 2010. Other expenditures in the quarter increased approximately $0.1 million as a result of increased maintenance on the Cold Lake pipeline system which was offset by lower maintenance on the Corridor system.

Year to date operating expenses increased by $4.5 million primarily due to a $3.5 million increase in power costs for the same reasons as noted above. Other operating expenses were approximately $1.0 million higher as a result of the timing associated with expenditures on maintenance and integrity projects on the Cold Lake pipeline system, which were partially offset by lower maintenance expenses on the Corridor pipeline system.

Capital Expenditures In the second quarter of 2010, approximately $27.0 million of growth capital was expended on the Corridor pipeline expansion project for a total of $1,642.6 million spent to date.

Final commissioning of the $1.8 billion Corridor expansion project continued as line fill activities on the new 42-inch diameter pipeline were completed and it was placed into service in May 2010.

10 Commissioning of the 24-inch diameter diluent pipeline was also completed and the line was placed into service. The new 20-inch diameter product pipeline is expected to be fully commissioned in the fall of 2010. Total forecast costs for the Corridor expansion project remain unchanged from its original forecast. The project is comprised of two distinct cost components. The first is a pipeline and facility construction component wherein Inter Pipeline was exposed to potential cost overruns. Inter Pipeline estimates that these costs are approximately $90 million under budget. The second cost component includes items such as storage tanks, interest during construction, line fill requirements and certain contingency cost factors. Inter Pipeline has no cost overrun exposure for these components as they will be added to the rate base at their actual cost.

Detailed engineering for Inter Pipeline’s Polaris diluent pipeline system began in 2010 and approximately $1.7 million has been spent on this project in the second quarter of 2010 for a total of $5.2 million to date. Beginning in late 2012, the Polaris system will provide diluent transportation services for the Kearl oil sands project utilizing the existing 12-inch diameter pipeline that has now been idled given the majority of the Corridor expansion project is in service. The asset value of the Polaris pipeline will be deducted from Corridor’s rate base at some point prior to entering diluent service for the Kearl project. Total incremental costs to connect the Polaris pipeline to the Kearl project and diluent receipt points in the Edmonton area are currently estimated to be $135 million.

NGL EXTRACTION BUSINESS SEGMENT Three Months Ended June 30 2010 2009 Mmcf/d (000s b/d) Mmcf/d (000s b/d) Propane Throughput Ethane plus Total Throughput Ethane Propane plus Total Cochrane 1,667 49.4 24.5 73.9 1,307 44.7 21.9 66.6 Empress V (100% basis) 964 19.4 10.0 29.4 170 3.5 2.1 5.6 Empress II 195 3.1 2.1 5.2 742 13.9 8.9 22.8 2,826 71.9 36.6 108.5 2,219 62.1 32.9 95.0

Six Months Ended June 30 2010 2009 Mmcf/d (000s b/d) Mmcf/d (000s b/d) Propane- Throughput Ethane plus Total Throughput Ethane Propane- plus Total Cochrane 1,844 51.0 26.4 77.4 1,685 49.3 26.0 75.3 Empress V (100% basis) 1,003 19.7 11.0 30.7 165 3.0 2.0 5.0 Empress II 168 2.8 1.9 4.7 1,010 18.7 12.0 30.7 3,015 73.5 39.3 112.8 2,860 71.0 40.0 111.0

11 Three Months Ended June 30 Six Months Ended June 30 (millions) 2010 2009 % change 2010 2009 % change Revenue (1) $ 143.4 $ 98.1 46.2 $ 316.5 $ 241.3 31.2 Shrinkage gas (1) $ 72.8 $ 51.9 40.3 $ 172.2 $ 135.0 27.6 Operating expenses (1) $ 28.4 $ 21.1 34.6 $ 54.4 $ 55.0 (1.1) Funds from operations (1) (2) $ 42.2 $ 25.2 67.5 $ 89.9 $ 51.3 75.2 Capital expenditures (1) Growth (2) $ 0.5 $ 3.7 $ 1.0 $ 7.8 Sustaining (2) 0.4 0.9 0.9 2.3 $ 0.9 $ 4.6 $ 1.9 $ 10.1

(1) Revenue, shrinkage gas, operating expenses, funds from operations and capital expenditures for the Empress V NGL extraction facility are recorded based on Inter Pipeline’s 50% ownership. (2) Please refer to the NON-GAAP FINANCIAL MEASURES section.

Volumes Inter Pipeline’s NGL extraction plants processed an average of 2,826 million cubic feet per day (mmcf/d) and 3,015 mmcf/d of natural gas during the three and six months ended June 30, 2010, respectively. This is approximately 607 mmcf/d higher than the second quarter and 155 mmcf/d higher than year to date 2009 periods. Volumes through the Cochrane facility increased in the second quarter and year to date in 2010 due to higher US west-coast demand for natural gas. Although production levels at the Cochrane facility were higher as a result of increased throughput volumes this was somewhat offset by a lower NGL content in the natural gas stream when compared to 2009.

Throughput volumes at Inter Pipeline’s Empress V facility increased in the second quarter of 2010 primarily due to the facility’s return to full operation in 2010. From January to mid June 2009, the Empress V facility was shut down for construction related to an ethane recovery improvement project which resulted in a short term increase to the gas supply available for processing at the Empress II facility. In 2010, the reduction in throughput volumes at Empress II is primarily due to the decline in natural gas exported from Alberta’s eastern border which has not significantly impacted operating results due to the cost-of-service processing arrangements related to this facility.

Revenue The NGL extraction business earns revenue from a combination of commodity based, fee-based and cost- of-service arrangements. Commodity based contracts provide for a sharing of profits from the sale of NGL products between the NGL extraction business and the purchaser. The profit share calculation consists of revenue from the sale of NGL products less costs to bring the NGL product to market, including extraction, shrinkage gas, fractionation and marketing costs. Commodity based contracts are exposed to frac-spread and volume risks. Fee-based contracts provide a fixed fee associated with each barrel of NGL produced and recovery of operating costs, including shrinkage gas costs. There is no commodity price exposure associated with this type of contract; however fee-based contracts are exposed to volume fluctuations. Cost-of-service contracts provide a structured return on capital invested utilizing a rate base approach and a recovery of operating costs, including shrinkage gas. This form of contract provides the most stable cash flow of the three contract types, as there is minimal volume risk and no commodity price exposure.

In 2010, revenue was approximately $45.3 million higher in the second quarter and $75.2 million higher year to date compared to the same periods in 2009. Higher realized frac-spreads, increased production at the Empress V facility and an increase in shrinkage, fuel gas and electricity cost recoveries from cost- of-service and fee based arrangements were the primary drivers.

12 Frac-spread Three Months Ended June 30 (dollars) 2010 2009 USD/USG (1) CDN/USG (1) USD/USG (1) CDN/USG (1) Market frac-spread $ 0.872 $ 0.895 $ 0.518 $ 0.604 Realized frac-spread $ 0.805 $ 0.826 $ 0.597 $ 0.697

Six Months Ended June 30 (dollars) 2010 2009 USD/USG (1) CDN/USG (1) USD/USG (1) CDN/USG (1) Market frac-spread $ 0.874 $ 0.904 $ 0.405 $ 0.487 Realized frac-spread $ 0.811 $ 0.838 $ 0.509 $ 0.615

(1) The differential between USD/USG and CDN/USG frac-spreads is due to fluctuations in exchange rates between US and Canadian dollars.

Market frac-spread is defined as the difference between the weighted average propane-plus price at Mont Belvieu, Texas and the monthly index price of AECO natural gas purchased for shrinkage calculated in US dollars per US gallon (USD/USG). This price is converted to Canadian dollars per US gallon (CDN/USG) based on the average monthly Bank of Canada CDN/USD noon rate. Realized frac-spread is defined in a similar manner and is calculated on a weighted average basis using market frac-spread for unhedged production and fixed-price frac-spread prices for the remaining hedged production. Propane- plus market price differentials, natural gas transportation and extraction premium costs have not been significant historically, therefore are not included in the calculation of realized frac-spread. See the RISK MANAGEMENT AND FINANCIAL INSTRUMENTS section for further discussion of frac-spread hedges.

Realized frac-spreads for the second quarter increased $0.21 USD/USG from $0.60 USD/USG in 2009 to $0.81 USD/USG in 2010. Frac-spreads in the three month period ended June 30, 2010 were above the 5- year and 15-year simple average market frac-spread of $0.59 USD/USG and $0.34 USD/USG, respectively, calculated at December 31, 2009.

Shrinkage Shrinkage gas represents natural gas bought by Inter Pipeline to replace the heat content of liquids extracted from natural gas processed at the Cochrane and Empress V facilities. The price for shrinkage gas is based on a combination of daily and monthly index AECO natural gas prices. In 2010, shrinkage gas expense increased approximately $20.9 million in the second quarter and $37.2 million year to date compared to the same periods in 2009 as a result of an increase in throughput volumes and an increase in AECO natural gas prices in the second quarter of 2010. The weighted average monthly AECO price 1 was $3.66 per gigajoule (GJ) in the second quarter of 2010, which was approximately 5.5% higher than the weighted average price 1 of $3.47/GJ in the same period in 2009. Year to date, the weighted average monthly AECO price 1 decreased 0.1% from $4.40/GJ in 2009 to $4.36/GJ in 2010.

Operating Expenses Operating expenses were approximately $7.3 million higher in the second quarter and $0.6 million lower year to date compared to the same periods in 2009. Fuel and power costs increased approximately $8.0 million in the second quarter of 2010 as a result of the increased throughput and significantly higher average Alberta power pool prices and AECO natural gas prices in 2010. Operating costs in the second quarter of 2010 were approximately $0.7 million lower than in 2009 due to the cost of major pressure vessel maintenance at the Empress V facility in 2009.

1 Weighted average price calculated from one-month spot prices at AECO as reported in the Canadian Gas Price Reporter .

13 Capital Expenditures During the second quarter of 2010, growth capital expenditures of approximately $0.5 million were spent on various projects at the Cochrane and Empress facilities, while an additional $0.4 million was spent on sustaining capital projects at the Cochrane facility.

CONVENTIONAL OIL PIPELINES BUSINESS SEGMENT Three Months Ended Six Months Ended June 30 June 30 Volumes (000s b/d) 2010 2009 % change 2010 2009 % change Bow River 108.8 119.4 (8.9) 110.6 119.3 (7.3) Central/Mid-Saskatchewan/Valley (1) 51.6 53.1 (2.8) 52.7 58.0 (9.1) 160.4 172.5 (7.0) 163.3 177.3 (7.9)

(millions) Revenue $ 37.7 $ 39.8 (5.3) $ 75.3 $ 78.4 (4.0) Operating expenses $ 10.2 $ 8.5 20.0 $ 19.0 $ 18.6 2.2 Funds from operations (2) $ 27.7 $ 31.8 (12.9) $ 55.8 $ 60.4 (7.6) Revenue per barrel (3) $ 2.55 $ 2.53 0.8 $ 2.58 $ 2.44 5.7 Capital expenditures Growth (2) $ 0.9 $ 6.6 $ 3.4 $ 8.1 Sustaining (2) 1.1 1.0 1.3 1.3 $ 2.0 $ 7.6 $ 4.7 $ 9.4

(1) Valley pipeline system was sold in April 2009. (2) Please refer to the NON-GAAP FINANCIAL MEASURES section. (3) Revenue per barrel represents total revenue of the conventional oil pipelines business segment divided by actual volumes.

Volumes Conventional oil pipeline volumes were approximately 12,100 b/d lower in the second quarter and 14,000 b/d lower year to date in 2010 compared to the same periods in 2009. In 2010, Bow River pipeline volumes decreased approximately 10,600 b/d in the second quarter and 8,700 b/d year to date as some producers bypassed Inter Pipeline’s truck terminal facilities to capitalize on strong heavy crude oil pricing differentials. Natural production declines also contributed to lower throughput volumes. Some of this decline in volume was partially offset by increased volumes on the Bow River Hardisty south section of the pipeline with the recent completion of a segregation project which delivers a segregated crude oil stream to refiners in Montana. The Mid-Saskatchewan pipeline system accounted for the remaining decline in volumes in the second quarter of 2010 primarily due to natural production declines and weather related issues.

Revenue Conventional oil pipeline revenue declined approximately $2.1 million in the second quarter and $3.1 million year to date in 2010 primarily due to the heavy crude oil pricing trends noted above. The reduction is mainly due to lower revenues from a storage and marketing agreement with Nexen. These revenues are down $6.7 million when compared to the second quarter of 2009 due to poorer blending economics in 2010. In addition, there was a deferred revenue credit in the 2009 second quarter which assisted blending revenues reaching an all time high in that period. The decline in volumes noted above were more than offset by mainline toll increases averaging approximately 6% in both January 2010 and July 2009, as well as increased revenue from additional volumes on the Bow River Hardisty south system.

Operating Expenses Operating expenses increased approximately $1.7 million in the second quarter of 2010 compared to 2009, of which $0.6 million is due to higher power costs. In the second quarter of 2009, spending on

14 integrity projects was lower due to the timing of integrity projects and the cancellation of integrity work on the Valley pipeline system as a result of its sale in that period. Year to date operating expenses increased approximately $0.4 million, primarily due to higher power costs in 2010....

Capital Expenditures Growth capital expenditures include final costs for the Bow River pipeline crude oil stream segregation project while sustaining capital expenditures relate to various projects.

BULK LIQUID STORAGE BUSINESS SEGMENT Three Months Ended Six Months Ended June 30 June 30 2010 2009 % change 2010 2009 % change Utilization 95.8% 95.9% (0.1) 95.7% 96.7% (1.0)

(millions) Revenue $ 23.9 $ 28.8 (17.0) $ 49.9 $ 58.9 (15.3) Operating expenses $ 12.7 $ 16.7 (24.0) $ 26.2 $ 33.7 (22.3) Funds from operations (1)(2) $ 15.3 $ 9.9 54.5 $ 25.5 $ 20.3 25.6 Capital expenditures Growth (2) $ 3.8 $ 8.0 $ 6.4 $ 15.2 Sustaining (2) 1.2 0.8 1.8 1.8 $ 5.0 $ 8.8 $ 8.2 $ 17.0

(1) In the second quarter of 2010, funds from operations for the bulk liquid storage business increased $5.8 million due to cash proceeds received for customer storage fees paid in advance. (2) Please refer to the NON-GAAP FINANCIAL MEASURES section.

Utilization Inter Pipeline, through its wholly owned subsidiary Simon Storage Limited (Simon Storage), owns eight deep-water bulk liquid storage terminals primarily servicing the petrochemical, petroleum and biofuel industries in the UK, Germany and Ireland. Considering the current European economic environment, demand for bulk liquid storage remains strong with tank utilization averaging more than 95% year to date in 2010. Demand for storage fluctuated historically due to market conditions within industry sectors and Simon Storage manages these fluctuations through customer and product diversification.

Revenue The business activities of Simon Storage consist primarily of bulk liquid storage and handling services. Simon Storage also offers a range of ancillary services to its customers through its engineering and facilities management divisions.

Revenue was approximately $4.9 million lower in the second quarter of 2010 as compared to the same period of 2009, of which approximately $4.5 million was attributed to foreign currency translation adjustments. Revenue generated from ancillary businesses declined approximately $2.6 million primarily due to the sale of the bulk liquid trucking business in the fourth quarter of 2009. Storage and handling revenue increased approximately $2.2 million due to new tankage constructed and in-service in the latter part of 2009, increases in storage rates and additional handling and heating services.

Year to date in 2010, revenue was approximately $9.0 million lower than in 2009, of which approximately $7.4 million related to foreign currency translation adjustments. The average year to date Pound Sterling /CDN exchange rate fell from 1.80 in 2009 to 1.58 in 2010, a decline of 12%. Revenue from ancillary businesses declined $5.3 million, which was partially offset by an increase of $3.4 million in storage and handling revenue.

15 Operating Expenses In 2010, operating expenses were lower by approximately $4.0 million in the second quarter and $7.5 million year to date compared to 2009 primarily due to foreign currency translation adjustments and sale of the bulk liquid trucking business.

Capital Expenditures Approximately $3.8 million in growth capital expenditures during the second quarter of 2010 related to a number of tank replacements, tank life extensions and tank modification projects at Immingham and other terminals. Growth capital expenditures included approximately $0.3 million, for a total of $7.5 million spent to date, on two tank conversion projects to support a new ten-year contract with Total UK Limited to store molten sulphur at the Immingham terminal. This project is now complete and revenue has commenced on this new contract.

Sustaining capital expenditures consisted of a variety of small projects relating to terminal infrastructure improvements, maintenance and safety focused initiatives.

OTHER EXPENSES Three Months Ended Six Months Ended June 30 June 30 (millions) 2010 2009 2010 2009 Depreciation and amortization $ 25.7 $ 23.9 $ 50.5 $ 49.1 Gain on disposal of assets - (19.9) - (19.9) Financing charges 9.6 9.0 18.9 19.9 General and administrative 9.5 10.4 20.3 20.3 Unrealized change in fair value of derivative financial instruments (13.3) 19.6 (20.4) 41.0 Fees to General Partner 1.9 1.7 3.9 3.4 Provision for (recovery of) income taxes 1.8 4.5 10.8 (19.0)

Depreciation and Amortization Depreciation and amortization of tangible and intangible assets in 2010 was higher than the same periods in 2009 as a result of Inter Pipeline’s 2009 and 2010 capital expenditure programs for assets now in-service.

Gain on Disposal of Assets Inter Pipeline recognized a gain of $19.9 million on the sale of the Valley pipeline system in April 2009 and disposal of other non-core assets in 2009.

16 Financing Charges Three Months Ended Six Months Ended June 30 June 30 (millions) 2010 2009 2010 2009 Interest on credit facilities $ 4.8 $ 4.8 $ 9.6 $ 13.4 Interest on loan payable to General Partner 5.8 6.0 11.6 12.0 Interest on debentures 2.3 0.9 3.9 2.5 Total financing charges 12.9 11.7 25.1 27.9 Capitalized interest (3.5) (2.7) (6.6) (8.0) Amortization of transaction costs on long-term debt 0.2 - 0.4 - $ 9.6 $ 9.0 $ 18.9 $ 19.9

Average short-term interest rates were lower in the second quarter of 2010 compared to 2009. The weighted average interest rate on Inter Pipeline’s credit facilities has declined approximately 20 basis points from 1.1% in the second quarter of 2009 to approximately 0.9% in 2010. Inter Pipeline’s weighted average credit facility debt outstanding increased approximately $176.7 million to $1,917.6 million in the second quarter of 2010 compared to $1,740.9 million in the same period in 2009 primarily due to expenditures on the Corridor expansion project.

On a year to date basis, average short-term interest rates declined substantially compared to 2009. The weighted average interest rate on Inter Pipeline’s credit facilities declined approximately 60 basis points from 1.5% in 2009 to approximately 0.9% in 2010. Inter Pipeline’s weighted average credit facility debt outstanding increased approximately $198.2 million to $1,929.9 million in 2010 compared to $1,731.7 million in the same period in 2009.

Interest expense on the loans payable to the General Partner decreased approximately $0.2 million in the second quarter and $0.4 million year to date in 2010 compared to the same periods in 2009. The decrease is due to the expiration on January 1, 2010 of a temporary 25 bps increase that was added to the loans to accommodate the Corridor expansion. Fixed interest rates on each of the $91.2 million and $288.6 million loans outstanding decreased 25 bps to 5.85% and 6.15%, respectively.

In 2010, debenture interest expense in the second quarter and year to date increased $1.4 million compared to the same periods in 2009. Interest rates on these debentures are fixed, however Inter Pipeline had swap agreements in place on each of the $150.0 million series A and B debentures that exchanged the fixed rates for variable rates. On February 2, 2010, the series A debentures matured and the associated interest rate swap agreement was terminated. On the same day, Corridor issued $150.0 million of 4.897% fixed rate series C senior, unsecured debentures that mature February 3, 2020 without acquiring a corresponding swap agreement.

See the LIQUIDITY AND CAPITAL RESOURCES section for further information about Inter Pipeline’s debt facilities and interest rate swaps.

General and Administrative

Three Months Ended Six Months Ended June 30 June 30 (millions) 2010 2009 2010 2009 Canada $ 8.1 $ 8.4 $ 17.5 $ 16.2 Europe 1.4 2.0 2.8 4.1 $ 9.5 $ 10.4 $ 20.3 $ 20.3

In Canada, general and administrative expenses decreased $0.3 million in the second quarter of 2010 due to lower employee compensation expenses partially offset by increased professional service and corporate overhead costs. Employee compensation expenses were lower resulting from the revaluation of Inter Pipeline’s long term deferred unit rights incentive plan. Year to date, general and administrative

17 expenses increased $1.3 million compared to 2009 also due to the revaluation of the long term incentive plan at June 30, 2010 and increases in professional service costs.

In Europe, general and administrative expenses were down approximately $0.6 million in the second quarter for a total of $1.3 million year to date in 2010 primarily due to the sale of the bulk liquid trucking business in 2009 and decline in foreign exchange rates.

Unrealized Change in Fair Value of Derivative Financial Instruments Inter Pipeline’s mark-to-market valuation of its derivative financial instruments impacted net income favourably by $13.3 million in the second quarter of 2010. Of this amount, changes in NGL and natural gas forward prices between April and June of 2010 combined with changes in volumes of NGLs under purchase and sale swap contracts resulted in a favourable net income impact of $19.9 million. These adjustments were partially offset by $7.7 million of changes in forward prices of foreign currency swaps for the same period.

Year to date Inter Pipeline’s mark-to-market valuation of its derivative financial instruments had a favourable impact on net income of $20.4 million. The change in NGL forward prices between January and June 2010, combined with changes in volumes under purchase and sale swap contracts, resulted in a $29.0 million favourable net income impact. This was partially offset by the mark-to-market valuations of natural gas hedges and foreign currency swaps year to date in 2010 decreasing net income by $8.2 million and $3.4 million, respectively.

See the RISK MANAGEMENT AND FINANCIAL INSTRUMENTS section for additional information on Inter Pipeline’s risk management initiatives.

Fees to General Partner Inter Pipeline paid a management fee to the General Partner of $1.9 million (Q2 2009 - $1.6 million) for a total of $3.9 million (YTD 2009 - $3.2 million) in 2010. This fee is equivalent to 2% of “Operating Cash,” as defined in the Limited Partnership Agreement (Partnership Agreement). A divestiture fee of $0.1 million was also paid in the second quarter of 2009 related to the sale of the Valley pipeline system.

Income Taxes Consolidated income tax expense for the six months ended June 30, 2010 increased $29.8 million from a net recovery of $19.0 million in 2009 to an income tax expense of $10.8 million in 2010. On March 4, 2009, the Government of Canada substantively enacted legislation that repealed the “provincial SIFT tax factor” and replaced it with a “provincial SIFT tax rate.” Inter Pipeline calculated the “provincial SIFT tax rate” based on the general provincial corporate income tax rate for each province where it has a permanent establishment. For Inter Pipeline, this legislation reduced the provincial income tax rate for non-corporate entities from 13.0% to approximately 10.0% effective January 1, 2011 onward. This also reduced Inter Pipeline’s estimated effective tax rate to 26.5% and 25.0% effective January 1, 2011 and January 1, 2012, respectively. As a result of this rate reduction, future income tax liabilities of non- corporate entities were reduced by $24.0 million in 2009. The remainder of the variance results from changes in temporary differences relating to non-taxable Canadian partnership income. Consolidated income tax expense for the three months ended June 30, 2010 decreased $2.7 million compared to the same period in 2009. The majority of this decrease resulted from changes in temporary differences relating to non-taxable Canadian partnership income.

18 SUMMARY OF QUARTERLY RESULTS

2008 2009 2010 (millions, except per unit and % Third Fourth First Second Third Fourth First Second amounts) Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter

Revenue Oil sands transportation $ 35.2 $ 35.1 $ 33.6 $ 30.6 $ 32.2 $ 34.1 $ 34.9 $ 36.4 NGL extraction (1) 231.4 149.8 143.2 98.1 127.3 160.5 173.0 143.4 Conventional oil pipelines 39.3 39.4 38.7 39.8 36.1 34.3 37.6 37.7 Bulk liquid storage 34.9 35.5 30.1 28.8 28.9 28.2 26.0 23.9 $ 340.8 $ 259.8 $ 245.6 $ 197.3 $ 224.5 $ 257.1 $ 271.5 $ 241.4

Funds from operations (3) Oil sands transportation $ 15.1 $ 17.3 $ 18.0 $ 17.9 $ 18.6 $ 19.4 $ 18.6 $ 18.9 NGL extraction (1) 47.8 13.1 26.2 25.2 40.9 40.8 47.6 42.2 Conventional oil pipelines 30.1 26.3 28.5 31.8 27.3 23.1 28.2 27.7 Bulk liquid storage (2) 10.9 11.3 10.5 9.9 20.8 10.4 10.3 15.3 Corporate costs (18.2) (15.9) (17.1) (16.3) (16.1) (15.5) (19.2) (15.8) $ 85.7 $ 52.1 $ 66.1 $ 68.5 $ 91.5 $ 78.2 $ 85.5 $ 88.3 Per unit (2) $ 0.39 $ 0.23 $ 0.30 $ 0.30 $ 0.37 $ 0.31 $ 0.33 $ 0.34

Net income $ 76.8 $ 102.5 $ 43.4 $ 39.3 $ 51.9 $ 23.1 $ 61.7 $ 67.9 Per unit – basic & diluted $ 0.34 $ 0.46 $ 0.19 $ 0.18 $ 0.21 $ 0.08 $ 0.24 $ 0.27

Cash distributions (4) $ 46.7 $ 46.8 $ 46.9 $ 48.6 $ 52.4 $ 54.5 $ 57.6 $ 57.8 Per unit (4) $ 0.210 $ 0.210 $ 0.210 $ 0.210 $ 0.210 $ 0.215 $ 0.225 $ 0.225

Units outstanding (basic) Weighted average 222.3 222.8 223.4 227.0 248.7 252.8 255.8 256.6 End of period 222.5 223.1 223.7 246.5 250.8 254.6 256.3 256.9

Capital expenditures Growth (3) $ 151.6 $ 101.0 $ 57.0 $ 46.0 $ 417.0 $ 53.5 $ 31.2 $ 34.2 Sustaining (3) 3.5 5.2 2.9 3.6 4.0 7.4 2.5 5.6 $ 155.1 $ 106.2 $ 59.9 $ 49.6 $ 421.0 $ 60.9 $ 33.7 $ 39.8

Payout ratio before sustaining capital (3) 54.5% 89.7% 71.0% 71.0% 57.2% 69.6% 67.4% 65.4% Payout ratio after sustaining capital (3) 56.9% 99.7% 74.3% 75.0% 59.9% 76.9% 69.4% 69.9%

Total debt (5) $ 2,264.8 $ 2,349.2 $ 2,406.5 $ 2,246.0 $ 2,610.8 $ 2,619.7 $ 2,576.8 $ 2,585.4 Total partners’ equity $ 1,075.7 $ 1,130.2 $ 1,130.5 $ 1,315.5 $ 1,319.3 $ 1,320.1 $ 1,314.2 $ 1,334.2 Enterprise value (3) $ 4,376.7 $ 3,921.8 $ 4,064.0 $ 4,392.9 $ 5,038.2 $ 5,372.4 $ 5,611.4 $ 5,655.7

Total recourse debt to capitalization (3) 42.6% 41.6% 42.2% 32.3% 35.2% 35.7% 34.4% 34.3% (3) Total debt to total capitalization 67.8% 67.5% 68.0% 63.1% 66.4% 66.5% 66.2% 66.0%

(1) Significant changes in propane-plus commodity prices and foreign exchange rates resulted in lower revenue and funds from operations in the fourth quarter of 2008 through to the third quarter of 2009. (2) In the third quarter of 2009 and second quarter of 2010, funds from operations for the bulk liquid storage business increased by $10.2 million and $5.8 million, respectively, due to a reclassification of cash proceeds received for customer storage fees paid in advance. On the consolidated statement of cash flows, these proceeds were reclassified from "net change in non-cash working capital" to "proceeds from long-term deferred revenue" which is included in the calculation of funds from operations. (3) Please refer to the NON-GAAP FINANCIAL MEASURES section of this MD&A. (4) Cash distributions are calculated based on the number of units outstanding at each record date. (5) Total debt includes long-term debt and short-term borrowings on demand loans before discounts and debt transaction costs.

19

LIQUIDITY AND CAPITAL RESOURCES Inter Pipeline’s capital management objectives are aligned with its commercial growth strategies and long-term outlook for the business. The primary objectives are to maintain:

(i) stable cash distributions to unitholders over economic and industry cycles; (ii) a flexible capital structure which optimizes the cost of capital within an acceptable level of risk; and (iii) an investment grade credit rating.

Management may make adjustments to the capital structure for changes in economic conditions or the risk characteristics of the underlying assets. To maintain or modify the capital structure, Inter Pipeline may adjust the level of cash distributions paid to unitholders, issue new partnership units or new debt, renegotiate new debt terms or repay existing debt.

Inter Pipeline maintains flexibility in its capital structure to fund organic growth capital and acquisition programs throughout market and industry cycles. Funding requirements are projected to ensure appropriate sources of financing are available to meet future financial obligations and capital programs. Inter Pipeline generally relies on committed credit facilities and cash flow from its operations to fund capital requirements. At June 30, 2010, Inter Pipeline had access to committed credit facilities totaling $2.9 billion, of which approximately $986.4 million remains unutilized. Inter Pipeline also had access to unutilized demand facilities of approximately $60 million. These facilities are available to fund foreseeable obligations, with certain amounts available to specific subsidiaries of Inter Pipeline.

Inter Pipeline also ensures a base of equity capital is available for some of its recently announced growth capital projects. Approximately $24.2 million of equity was issued through the distribution reinvestment plan during the first six months of 2010.

Taking future market trends into consideration, Inter Pipeline regularly forecasts its operational requirements and expected funds from operations to ensure that sufficient funding is available for future sustaining capital programs and distributions to unitholders.

Inter Pipeline utilizes derivative financial instruments to minimize exposure to fluctuating commodity prices, foreign exchange and interest rates. Inter Pipeline’s risk management policy defines and specifies the controls and responsibilities to manage market exposure to changing commodity prices (crude oil, natural gas, NGL and power) and changes within financial markets relating to interest rates and foreign exchange exposure. Further details of the risk management program are discussed in the RISK MANAGEMENT AND FINANCIAL INSTRUMENTS section.

20 CAPITAL STRUCTURE June 30 December 31 (millions, except % amounts) Recourse Non-recourse 2010 2009 Credit facilities available Corridor syndicated facility $ 488.0 $ 1,654.0 $ 2,142.0 $ 2,142.0 Inter Pipeline syndicated facility 750.0 - 750.0 750.0 1,238.0 1,654.0 2,892.0 2,892.0 Demand facilities (1) 20.0 40.0 60.0 60.0 $ 1,258.0 $ 1,694.0 $ 2,952.0 $ 2,952.0

Total debt outstanding Recourse Corridor syndicated facility $ 165.3 $ 123.6 Inter Pipeline syndicated facility 152.5 230.0 Loan payable to General Partner 379.8 379.8 Non-recourse Corridor syndicated facility 1,587.8 1,586.3 Corridor debentures 300.0 300.0 Total debt (1)(2) 2,585.4 2,619.7 Total partners' equity 1,334.2 1,320.1 Total capitalization (3) $ 3,919.6 $ 3,939.8

Total debt to total capitalization (3) 66.0% 66.5% Total recourse debt to capitalization (3) 34.3% 35.7%

(1) At December 31, 2009 and June 30, 2010, outstanding Corridor letters of credit were approximately $0.3 million which are not included in the demand loan facilities or total debt outstanding in the table above. (2) At June 30, 2010, total debt includes long-term debt of $2,576.6 million inclusive of discounts and debt transaction costs of $8.8 million. (3) Please refer to the NON-GAAP FINANCIAL MEASURES section of this MD&A.

Inter Pipeline’s capital under management includes financial debt and partners’ equity. Capital availability is monitored through a number of measures, including total recourse debt to capitalization and recourse debt to EBITDA. Capital management objectives are to provide access to capital at a reasonable cost while maintaining an investment grade long-term corporate credit rating and ensure compliance with all debt covenants. Financial covenants on Inter Pipeline’s credit facilities are based on the amount of recourse debt outstanding. Management’s objectives are to remain well below its maximum target ratio of 65% recourse debt to capitalization and maximum recourse debt to EBITDA rate of 4.25. Recourse debt is attributed directly to Inter Pipeline and used in the calculation of its financial covenants. Inter Pipeline’s recourse debt to capitalization ratio was a favourable 34.3% at June 30, 2010. Adjusting for the impact of non-recourse debt of $1,887.8 million, Inter Pipeline’s consolidated debt to total capitalization ratio was 66.0%.

At June 30, 2010, approximately $2,013.6 million or 77.9% of Inter Pipeline’s total consolidated debt was exposed to variable interest rates, however debt financing costs related to $1,903.1 million of Corridor debt outstanding are directly recoverable through the terms of the Corridor FSA. Therefore, Inter Pipeline’s direct interest rate risk associated with variable rate debt is only attributable to $110.5 million or 4.3% of total outstanding debt. When deemed appropriate, Inter Pipeline enters into interest rate swap agreements to manage its interest rate risk exposure. In 2001, Inter Pipeline entered into two fixed interest rate swap agreements to manage a portion of its variable interest rate risk exposure. In 2007, Inter Pipeline acquired two variable interest rate swap agreements to manage fixed interest rate exposure on Corridor’s 5 and 10-year debentures. The interest rate swap associated with Corridor’s 5- year debentures was terminated when the underlying debenture matured on February 2, 2010.

21 June 30, 2010 December 31, 2009 Fixed Rate Per Fixed Rate Per Annum Notional Annum Notional (excluding Balance (excluding Balance applicable applicable Maturity date margin) (millions)margin) (millions) Corridor debentures - Fixed to floating rate swap Series A - February 2, 2010 4.240%$ - 4.240%$ 150.0 Series B - February 2, 2015 5.033% 150.0 5.033% 150.0 $ 150.0 $ 300.0

Inter Pipeline syndicated facility - Floating to fixed rate swap December 30, 2011 (1) 6.300%$ 27.0 6.300%$ 27.0 December 31, 2011 6.310% 15.0 6.310% 15.0 $ 42.0 $ 42.0

(1) The notional principal balance of the $27.0 million interest rate swap is reduced by $1.0 million each year for the term of the arrangement.

Inter Pipeline has maintained its investment grade, long-term corporate credit rating of BBB with S&P since 2003. Corridor’s series B and C debentures have been assigned investment grade credit ratings of A, A3 and A- from DBRS, Moody’s and S&P, respectively. Subsequent to June 30 2010, DBRS increased Inter Pipeline’s investment grade credit, long-term corporate credit rating to BBB (high) with a stable trend, up from BBB. In addition, DBRS also increased the credit rating of Inter Pipeline’s 100% owned subsidiary, Inter Pipeline (Corridor) Inc. to A from A (low).

CONTRACTUAL OBLIGATIONS , COMMITMENTS AND GUARANTEES The following table summarizes Inter Pipeline’s commitment profile and future contractual obligations at June 30, 2010. Management intends to finance these commitments through existing credit facilities and cash flow from operations. Longer term commitments will be funded through Inter Pipeline’s capital management polices as discussed in the section above.

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Less than one (millions) Total year 1 to 5 years After 5 years Capital expenditure projects (1) Oil sands transportation $ 338.0 $ 220.4 $ 117.6 $ - NGL extraction 49.0 13.0 36.0 - Conventional oil pipelines 9.6 5.6 4.0 - Bulk liquid storage 8.6 8.6 - - Growth capital (2) 405.2 247.6 157.6 - Sustaining capital (2) 9.9 9.9 - - 415.1 257.5 157.6 - Total debt (3) Corridor syndicated facility 1,753.1 165.3 1,587.8 - Inter Pipeline syndicated facility 152.5 - 152.5 - Loan to General Partner 379.8 - 379.8 - Corridor debentures 300.0 - 150.0 150.0 2,585.4 165.3 2,270.1 150.0 Other obligations Derivative financial instruments 21.7 17.1 4.6 - Operating leases (4) 83.1 6.6 25.0 51.5 Purchase obligations 89.6 2.0 19.5 68.1 Long term portion of incentive plan 3.6 - 3.6 - Working capital deficit (2) 27.5 27.5 - - $ 3,226.0 $ 476.0 $ 2,480.4 $ 269.6

(1) Capital expenditures “less than one year” represent expected expenditures for the remaining months of 2010. (2) Please refer to the NON-GAAP FINANCIAL MEASURES section of this MD&A. (3) At June 30, 2010, outstanding Corridor letters of credit of approximately $0.3 million were not included in the total $2,585.4 million of debt outstanding in the table above. (4) Operating lease maturities are based on contract terms as presented at December 31, 2009.

Inter Pipeline plans to invest approximately $405.2 million in organic growth capital projects over the 2010 to 2012 period which includes final costs on the Corridor pipeline expansion project, capital costs for the $135 million Polaris oil sands diluent transportation project and $50 million for a sweetening project at the Cochrane NGL extraction facility. Inter Pipeline is also committed to investing capital in the bulk liquid storage business to comply with the UK’s post Buncefield regulations. Potential solutions are being evaluated and expenditures are estimated to be in the range of $4.8 million to $9.5 million phased over the next ten years. Subsequent to June 2010, Inter Pipeline announced a $40 million expansion project on the Cold Lake pipeline system to increase transportation capacity for the Foster Creek oil sands project. Funding of significant capital projects is managed as discussed in the capital structure section.

Inter Pipeline’s debt outstanding at June 30, 2010 matures at various dates up to February 2020. Corridor’s series B debentures will mature in February 2015 and Corridor’s series C debentures mature February 3, 2020. Amounts drawn on tranches A and B of Corridor’s syndicated facility will mature in 2012. Amounts drawn on tranches C and D of this facility will mature the earlier of August 2012 and the commencement or suspension true-up date of the Corridor expansion project. Inter Pipeline’s loan payable to the General Partner and Inter Pipeline syndicated facility mature in periods between 2012 and 2014.

The following future obligations resulting from normal course of operations would be primarily funded from operations in the respective periods that they become due or may be funded through long-term debt.

(i) Derivative financial instruments are utilized to manage market risk exposure to changes in commodity prices, foreign currencies and interest rates in future periods. This future obligation is an

23 estimate of the fair value liability on an undiscounted basis for financially net settled derivative contracts outstanding at June 30, 2010, based upon the various contractual maturity dates.

(ii) Operating leases and purchase obligations represent minimum payment obligations associated with leases and normal operating agreements for periods up to 2038.

(iii) Working capital deficiencies arise primarily from capital expenditures outstanding in accounts payable at the end of a period, and fluctuate with changes in commodity prices.

(iv) Inter Pipeline has obligations of $19.3 million under its employee incentive plan, of which $15.7 million is included in the working capital deficit.

(v) Undiscounted asset retirement obligations of $55.2 million at December 31, 2009 represent an estimate of future obligations for the retirement of NGL extraction and bulk liquid storage assets. Similarly, long term environmental liabilities of $11.8 million represent an estimate of projects that Inter Pipeline is obligated to remediate in the future. Defined benefit pension obligations of $11.1 million represent the unfunded portion of the European retirement plans at December 31, 2009. Since there is no specified timing for payment of these obligations, they were excluded in the table above.

CASH DISTRIBUTIONS TO UNITHOLDERS

Three Months Ended Six Months Ended June 30 June 30 (millions) 2010 2009 2010 2009 Cash provided by operating activities $ 88.3 $ 61.5 $ 214.5 $ 128.3 Net change in non-cash working capital (1) - 7.0 (40.8) 6.3 Less sustaining capital expenditures (2) (5.6) (3.6) (8.1) (6.6) Cash available for distribution (2) 82.7 64.9 165.6 128.0 Change in discretionary reserves (24.9) (16.3) (50.2) (32.5) Cash distributions $ 57.8 $ 48.6 $ 115.4 $ 95.5 Cash distributions per unit (3) $ 0.225 $ 0.210 $ 0.450 $ 0.420

Payout ratio before sustaining capital (2) 65.4% 71.0% 66.4% 71.0% Payout ratio after sustaining capital (2) 69.9% 75.0% 69.7% 74.6%

Growth capital expenditures (2) $ 34.2 $ 46.0 $ 65.4 $ 103.0 Sustaining capital expenditures (2) 5.6 3.6 8.1 6.6 $ 39.8 $ 49.6 $ 73.5 $ 109.6

(1) In the second quarter 2010, funds from operations for the bulk liquid storage business increased $5.8 million due to cash proceeds received for customer storage fees paid in advance. (2) Please refer to the NON-GAAP FINANCIAL MEASURES section of this MD&A. (3) Cash distributions are calculated based on the number of units outstanding at each record date.

It is the policy of the General Partner to provide unitholders with stable cash distributions over time. As a result, not all cash available for distribution is distributed to unitholders. Rather, a portion of cash available for distribution is reserved and reinvested in the business to effectively manage its capital structure, and in particular, debt levels. The General Partner makes its cash distribution decisions based on the underlying assumptions in each year’s annual operating and capital budget and long term forecast, consistent with its policy to provide unitholders with stable cash distributions.

24 “Cash available for distribution” is a non-GAAP financial measure that the General Partner uses in managing Inter Pipeline’s business and in assessing future cash requirements that impact the determination of future distributions to unitholders. Inter Pipeline defines cash available for distribution as cash provided by operating activities less net changes in non-cash working capital and sustaining capital expenditures. The impact of net change in non-cash working capital is excluded in the calculation of “Cash available for distribution” primarily to compensate for the seasonality of working capital throughout the year. Certain Inter Pipeline revenue contracts dictate an exchange of cash that differs, on a monthly basis, from the recognition of revenue. Within a 12-month calendar year, there is minimal variation between revenue recognized and cash exchanged. Inter Pipeline therefore excludes the net change in non-cash working capital in its calculation of cash available for distribution to mitigate the quarterly impact this difference has on cash available for distribution. The intent is to not skew the results of Inter Pipeline in any quarter for exchanges of cash, but to focus the results on cash that is generated in any reporting period.

In addition, in determining actual cash distributions, Inter Pipeline applies a discretionary reserve to cash available for distribution, which is designed to ensure stability of distributions over economic and industry cycles and to enable Inter Pipeline to absorb the impact of material one-time events. Therefore, not all cash available for distribution is necessarily distributed to unitholders. The reconciliation is prepared using reasonable and supportable assumptions, reflecting Inter Pipeline’s planned course of action in light of management and the board of directors’ judgment regarding the most probable set of economic conditions. Investors should be aware that actual results may vary, possibly materially, from such forward-looking adjustments.

The discretionary reserve increased approximately $24.9 million in the second quarter of 2010 and $50.2 million year to date due primarily to the strong operating results of Inter Pipeline’s business segments. Inter Pipeline will continue to manage the discretionary reserve and future cash distributions in accordance with its policy of attempting to manage the stability of distributions through industry and economic cycles.

The tables below show Inter Pipeline’s cash distributions paid relative to cash provided by operating activities and net income (loss) for the periods indicated. See the OUTLOOK section of this report and RISK FACTORS section for further information regarding the sustainability of cash distributions.

Three months Six months ended ended Years Ended June 30 June 30 December 31 (millions) 2010 2010 2009 2008 2007 2006 Cash provided by operating activities $ 88.3 $ 214.5 $ 281.8 $ 321.1 $ 234.1 $ 201.6 Cash distributions (57.8) (115.4) (202.4) (186.6) (171.7) (160.8) Excess $ 30.5 $ 99.1 $ 79.4 $ 134.5 $ 62.4 $ 40.8

Three months Six months ended ended Years Ended June 30 June 30 December 31 (millions) 2010 2010 2009 2008 2007 2006 Net income (loss)$ 67.9 $ 129.6 $ 157.7 $ 249.7 $ (80.0) $ 130.6 Cash distributions (57.8) (115.4) (202.4) (186.6) (171.7) (160.8) Excess (shortfall)$ 10.1 $ 14.2 $ (44.7) $ 63.1 $ (251.7) $ (30.2)

Cash distributions in all periods are less than cash provided by operating activities and in the three and six months ended June 30, 2010 and year ended 2008 were less than net income. Net income (loss) includes certain non-cash expenses such as depreciation and amortization, future income taxes and unrealized changes in the fair value of derivative financial instruments therefore cash distributions may exceed net income.

25 The overall cash distributions of Inter Pipeline are governed by the Partnership Agreement, specifically section 5.2 of the Partnership Agreement, that specifies the terms for Inter Pipeline to make distributions of cash as defined in the Partnership Agreement (Distributable Cash) on a monthly basis, provided that Inter Pipeline has cash available for such payment (thereby excluding any cash withheld as a reserve). Distributable Cash is defined to generally mean cash from operating, investing and financing activities, less certain items, including any cash withheld as a reserve that the General Partner determines to be necessary or appropriate for the proper management of Inter Pipeline and its assets. As a result of the General Partner’s discretion to establish reserves under the Partnership Agreement, cash distributed to unitholders is always equal to Distributable Cash.

OUTSTANDING UNIT DATA Inter Pipeline’s outstanding units at June 30, 2010 are as follows:

(millions) Class A Class B Total Units outstanding 256.6 0.3 256.9

Inter Pipeline had 10,500 units reserved for issuance upon the exercise of vested Unit Incentive Options as at June 30, 2010, which were exercised in July 2010. At August 3, 2010 Inter Pipeline had 256.8 million Class A units and 0.3 million Class B units for a total of 257.1 million units outstanding.

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS MARKET RISK MANAGEMENT Inter Pipeline utilizes derivative financial instruments to manage liquidity and market risk exposure to changes in commodity prices, foreign currencies and interest rates. Risk management policies are intended to minimize the volatility of Inter Pipeline’s exposure to commodity price, foreign exchange and interest rate risk to assist with stabilizing funds from operations. Inter Pipeline endeavours to accomplish this primarily through the use of derivative financial instruments. Inter Pipeline’s policy prohibits the use of derivative financial instruments for speculative purposes. All hedging policies are authorized and approved by the board of directors through Inter Pipeline’s risk management policy.

Inter Pipeline has the following types of derivative financial instruments: commodity price swap agreements, foreign currency exchange contracts, power price hedges and heat rate and interest rate swap agreements. The mark-to-market or fair value of these financial instruments are recorded as an asset or liability and any change in the fair value recognized as an unrealized change in fair value of these derivative financial instruments in the calculation of net income. When the financial instrument matures, any realized gain or loss is recorded in net income.

In the following sections, sensitivity analyses are presented to provide an indication of the amount that an isolated change in one variable may have on earnings 1. Changes in fair value generally cannot be extrapolated based on one variable because the relationship with other variables may not be linear. In reality, changes in one variable may magnify or counteract the impact of another variable which may result in a significantly different conclusion. The sensitivity analyses in the following sections are based on the value of derivative financial instruments and long-term debt outstanding at June 30, 2010. The analyses are hypothetical and should not be considered to be predictive of future performance.

NGL Extraction Business FracFrac----spreadspread Risk Management Inter Pipeline is exposed to frac-spread risk which is the difference between the weighted average propane-plus price at Mont Belvieu, Texas and the monthly index price of AECO natural gas purchased for

1 Some of the sensitivity analyses presented below present the effect of reasonably possible changes in risk variables on essentially a pre-tax basis since prior to 2011, Inter Pipeline is only taxable on corporations within its organizational structure. Therefore the analyses in some of the sections below assume nil income tax impact.

26 shrinkage calculated in USD/USG. Derivative financial instruments are utilized to manage frac-spread risk. Inter Pipeline transacts with third party counterparties to sell a notional portion of its NGL products and related notional quantities of natural gas at fixed prices. NGL price swap agreements are transacted in US currency therefore Inter Pipeline also enters into foreign exchange contracts to sell US dollars to convert notional US dollar amounts in the NGL swaps.

The following table presents the proportion of future propane-plus volumes hedged under contracts outstanding and the average net price of the frac-spread hedges. The CDN/USG average prices would approximate the following USD/USG prices based on the average USD/CDN forward curve at June 30, 2010.

June 30, 2010

% Forecast Propane- plus Average Average Volumes Price Price Hedged (CDN/USG) (USD/USG) July to December 2010 52% $ 0.74 $ 0.70 January to December 2011 31% $ 0.75 $ 0.70

Based on propane-plus volume hedges outstanding at June 30, 2010, the following table illustrates how a 10% change in NGL and AECO natural gas commodity prices or foreign exchange rates in isolation could individually impact the mark-to-market valuation of Inter Pipeline’s derivative financial instruments and consequently after-tax income assuming rates associated with each of the other components and all other variables remain constant:

Change in net Change in net Fair value of income based on income based on derivative financial 10% increase in 10% decrease in instruments prices/rates (1) prices/rates (1) NGL (2) $ 19.7 $ (10.9) $ 10.9 AECO natural gas (14.2) 4.0 (4.0) Foreign exchange (4.3) (12.5) 12.5 Frac-spread risk management$ 1.2

(1) Negative amounts represent a liability increase or asset decrease. Changes related to 2011 contracts are net of tax of 26.5%. (2) Assumes that a commodity price change will impact all propane, normal butane, isobutane and pentanes-plus products linearly.

Power Price Risk Management Inter Pipeline uses derivative financial instruments to manage power price risk in its NGL extraction and conventional oil pipelines business segments. In 2009, Inter Pipeline entered into financial heat rate swap and power price swap contracts to manage power price risk exposure in these businesses.

Based on heat rate swaps outstanding in the NGL extraction business at June 30, 2010, a 10% change in Alberta power pool commodity prices in isolation with all other variables held constant, could potentially change the mark-to-market valuation of Inter Pipeline’s derivative financial instruments used to manage power price risk and consequently after-tax income by approximately $0.6 million. A 10% change in AECO natural gas prices in isolation with all other variables held constant, could potentially change the mark-to-market valuation of Inter Pipeline’s derivative financial instruments used to manage power price risk and consequently after-tax income by approximately $0.4 million.

Based on electricity price swap agreements outstanding in the conventional oil pipelines business at June 30, 2010, a 10% change in Alberta power pool commodity prices in isolation with all other variables held constant, could potentially change the mark-to-market valuation of Inter Pipeline’s derivative

27 financial instruments used to manage power price risk and consequently after-tax income by approximately $0.1 million.

Bulk Liquid Storage Business Foreign Exchange Risk Management Inter Pipeline is exposed to currency risk resulting from the translation of assets and liabilities of its European bulk liquid storage operations and transactional currency exposures arising from purchases in currencies other than Inter Pipeline’s functional currency, the Canadian dollar. Transactional foreign currency risk exposures have not been significant historically, therefore are generally not hedged; however, Inter Pipeline may decide to hedge this risk in the future.

Corporate Interest Rate Risk Management Inter Pipeline’s exposure to interest rate risk primarily relates to its long-term debt obligations and fair valuation of its floating-to-fixed interest rate swap agreements. Inter Pipeline manages its interest rate risk by balancing its exposure to fixed and variable rates while minimizing interest costs. When deemed appropriate, Inter Pipeline enters into interest rate swap agreements to manage its interest rate price risk exposure.

Based on the variable rate obligations outstanding at June 30, 2010, a 1% change in interest rates at this date could affect interest expense on credit facilities and consequently pre-tax income by approximately $4.8 million and $9.5 million, respectively, for the three and six months ending June 30, 2010, assuming all other variables remain constant. Of this amount, $4.4 million and $8.7 million for the three and six months ending June 30, 2010, respectively, relates to the $2.1 billion Corridor credit facility and are also recoverable in pre-tax income through the terms of the Corridor FSA. A 1% change in interest rates at June 30, 2010 could also affect the mark-to-market valuation of Inter Pipeline’s derivative financial instruments used to manage interest rate risk and consequently after-tax income by approximately $0.5 million, assuming all other variables remain constant.

Realized and Unrealized Gains (Losses) on Derivative Instruments - Held-for- Trading Derivative financial instruments designated as "held-for-trading" are recorded on the consolidated balance sheet at fair value. Any gain or loss upon settlement of these contracts is recorded as a realized gain or loss in net income. Prior to settlement, any change in the fair value of these instruments are recognized in net income as an unrealized change in fair value of derivative financial instruments.

The fair values of derivative financial instruments are calculated by Inter Pipeline using a discounted cash flow methodology with reference to actively quoted forward prices and/or published price quotations in an observable market and market valuations provided by counterparties. Forward prices for NGL swaps are less transparent because they are less actively traded. Forward prices are assessed based on available market information for the time frames for which there are derivative financial instruments in place. Fair values are discounted using a risk-free rate plus a credit premium that takes into account the credit quality of the instrument.

28 Gains (losses) on derivative financial instruments recognized in the calculation of net income are as follows: Three Months Ended Six Months Ended June 30 June 30 (millions) 2010 2009 2010 2009 Realized (loss) gain on derivative financial instruments Revenues NGL swaps $ 1.6 $ 16.5 $ 0.2 $ 35.3 Foreign exchange swaps (frac-spread hedges) 0.4 (4.2) 0.5 (10.5) 2.0 12.3 0.7 24.8

Shrinkage gas expense Natural gas swaps (4.9) (8.0) (7.0) (13.2)

Operating expenses Electricity price swaps 0.3 - 0.2 - Heat rate swaps 1.3 0.1 1.2 0.6 1.6 0.1 1.4 0.6 Financing charges Interest rate swaps 0.8 2.0 2.2 3.3 Total realized (loss) gain on derivative financial instruments (0.5) 6.4 (2.7) 15.5

Unrealized gain (loss) on derivative financial instruments NGL swaps 14.4 (38.3) 29.0 (51.5) Natural gas swaps 5.5 4.4 (8.2) (3.7) Foreign exchange swaps (frac-spread hedges) (7.7) 14.1 (3.4) 14.7 Electricity price swaps 0.3 - 0.2 - Heat rate swaps 0.8 (0.7) 2.3 (1.4) Interest rate swaps 0.2 1.1 0.9 1.3 Transitional transfers 1 (0.2) (0.2) (0.4) (0.4) Total unrealized gain (loss) on derivative financial instruments 13.3 (19.6) 20.4 (41.0) Total gain (loss) on derivative financial instruments $ 12.8 $ (13.2) $ 17.7 $ (25.5)

(1) Transfer of gains and losses on derivatives previously designated as cash flow hedges from accumulated other comprehensive income.

CREDIT RISK Inter Pipeline’s credit risk exposure relates primarily to customers and financial counterparties holding cash and derivative financial instruments, with a maximum exposure equal to the carrying amount of these instruments. Credit risk is managed through credit approval and monitoring procedures. The creditworthiness assessment takes into account available qualitative and quantitative information about the counterparty including, but not limited to, financial status and external credit ratings. Depending on the outcome of each assessment, guarantees or some other credit enhancement may be requested as security. Inter Pipeline attempts to mitigate its exposure by entering into contracts with customers that may permit netting or entitle Inter Pipeline to lien or take product in kind and/or allow for termination of the contract on the occurrence of certain events of default. Each business segment monitors outstanding accounts receivable on an ongoing basis.

Concentrations of credit risk associated with accounts receivable relate to a limited number of principal customers in the oil sands transportation and NGL extraction business segments, the majority of which are affiliated with investment grade corporations in the energy and chemical industry sectors. At June 30, 2010, accounts receivable associated with these two business segments were $65.8 million or 65% of total accounts receivable outstanding. Inter Pipeline believes the credit risk associated with the remainder of accounts receivable is minimized due to diversity across business units and customers.

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With respect to credit risk arising from cash, deposits and derivative financial instruments, Inter Pipeline believes the risk of non-performance of counterparties is minimal as cash, deposits and derivative financial instruments outstanding are predominantly held with major financial institutions or investment grade corporations.

Inter Pipeline actively monitors the risk of non-performance of its customers and financial counterparties. At June 30, 2010, accounts receivable outstanding meeting the definition of past due and impaired is immaterial.

TRANSACTIONS WITH RELATED PARTIES No revenue was earned from related parties in the quarters ended June 30, 2010 or 2009.

Upon acquisition of the General Partner in 2002, Pipeline Assets Corp. (PAC), the sole shareholder of the General Partner, assumed the obligations of the former general partner of Inter Pipeline under a support agreement. The support agreement obligates the affiliates controlled by PAC to provide certain personnel and services if requested by the General Partner, to fulfill its obligations to administer and operate Inter Pipeline’s business. Such services are incurred in the normal course of operations and amounts paid for such services are at cost for the services provided. No amounts have been paid under the terms of the support agreement since PAC acquired its interests in the General Partner.

The General Partner’s 0.1% interest in Inter Pipeline, represented by Class B units, is controlled by PAC. The General Partner is a wholly owned subsidiary of PAC, a corporation controlled solely by the Chairman of the Board of the General Partner. Certain officers and directors of the General Partner have non-voting shares in PAC that entitle them to dividends. Officers and directors of the General Partner received $0.3 million (Q2 2009 - $0.2 million) in dividends in the second quarter of 2010 from PAC pursuant to their ownership of non-voting shares.

Under the Partnership Agreement, the General Partner is entitled to recover all direct and indirect expenses, including general and administrative expenses, incurred on behalf of Inter Pipeline. The General Partner also receives an annual base fee equal to 2% of Inter Pipeline’s annual “Operating Cash” as defined in the Partnership Agreement. In addition, the General Partner is entitled to earn an annual incentive fee of between 15% and 35% of Inter Pipeline’s annual Distributable Cash as defined in the Partnership Agreement in excess of $1.01 per unit to $1.19 per unit respectively; an acquisition fee of 1.0% of the purchase price of any assets acquired by Inter Pipeline (excluding the pipeline assets originally acquired); and a disposition fee of 0.5% of the sale price of any assets sold by Inter Pipeline. See the Other Expenses section of RESULTS OF OPERATIONS for details of fees paid to the General Partner during the period.

In 2004, Inter Pipeline entered into a loan agreement with the General Partner for $379.8 million. At the same time, the General Partner had received $379.8 million by way of a Private Placement note issuance to a combination of American and Canadian institutional investors and immediately loaned the funds to Inter Pipeline. At June 30, 2010, interest payable to the General Partner on the loan was $4.1 million (June 30, 2009 - $4.3 million). This loan to Inter Pipeline from the General Partner has the identical repayment terms and commitments as the notes payable by the General Partner to the institutional note holders, except for an interest rate increase of 0.05% over the rates payable on the notes issued by the General Partner. Inter Pipeline has guaranteed the notes issued by the General Partner to the note holders. The guarantee may be exercised in the event of default by the General Partner pursuant to the terms of the Note Purchase Agreement and is equal to the amount of principal outstanding at the time of default, including a premium of 50 bps over the implied yield to maturity, accrued interest and, if applicable, swap breakage costs.

Amounts due to/from the General Partner and its affiliates related to services are non-interest bearing and have no fixed repayment terms with the exception of the loan agreement with the General Partner

30 as noted above. At June 30, 2010, there were amounts owed to the General Partner by Inter Pipeline of $0.6 million (June 30, 2009 – $0.5 million).

CONTROLS AND PROCEDURES Management has made no material changes to the design of Inter Pipeline’s internal control over financial reporting during the second quarter or year to date 2010.

CRITICAL ACCOUNTING ESTIMATES The preparation of Inter Pipeline’s consolidated financial statements requires management to make critical and complex judgments, estimates and assumptions about future events, when applying GAAP, that have a significant impact on the financial results reported. These judgments, estimates, and assumptions are subject to change as future events occur or new information becomes available. Readers should refer to note 1 Summary of Significant Accounting Policies of the December 31, 2009 consolidated financial statements for a list of Inter Pipeline’s significant accounting policies.

There were no changes in Inter Pipeline’s critical accounting estimates as disclosed in its annual 2009 MD&A that affected the disclosure or the accounting for its operations for the quarter ended June 30, 2010.

CHANGES IN ACCOUNTING POLICIES FUTURE International Financial Reporting Standards (IFRS) All Canadian publicly accountable enterprises are required to adopt IFRS for interim and annual reporting periods for fiscal years beginning on or after January 1, 2011. For fiscal 2010, Inter Pipeline will continue to present its results using GAAP. In fiscal 2011, Inter Pipeline will present its results under the principles of IFRS, with fiscal 2010 results restated for comparative purposes.

Inter Pipeline commenced its IFRS conversion project in 2008 and established a project team to successfully manage the transition to IFRS within the required timeframe. Inter Pipeline’s project plan has been designed to ensure full compliance with IFRS, considering the impact on business and accounting processes, contractual and financing arrangements, key metrics, information systems and control environment. The project team reports to a steering committee comprised of senior management with quarterly updates to the audit committee. Inter Pipeline’s external auditors have also been involved throughout the process from the initial impact assessment phase to the review of position papers.

Financial Statement Compliance with IFRS Milestones/ Deadlines Initial impact assessment phase
Initial identification of the major differences between current Canadian GAAP Completed. and IFRS standards and assessment of the impact of these differences into high, medium and low categories in terms of the complexity of implementation and prospective timelines. Research and planning phase
Research specific differences between the standards, long-term and Research transitional options available and prospective changes to the IFRS standards substantially prior to 2011. Identify potential implications on accounting policies and completed subject processes, business management, information systems, control environment to monitoring and educational requirements. Develop a formal plan and timeline to meet updates as IFRS project objectives. standards change.

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Solution development phase In process with
Quantify and evaluate transitional and long-term options available and select financial the most appropriate policies. statements to be fully compliant Implementation phase with IFRS for the
Integrate solutions into the underlying financial processes and systems. 2011 fiscal year.

Inter Pipeline is currently in the process of quantifying the impact of certain IFRS standards and revising financial statement disclosures to comply with IFRS requirements. The International Accounting Standards Board (IASB) has a number of ongoing projects that could impact Inter Pipeline’s consolidated financial statements on transition and in the future. The project team monitors the progress of new standards and proposed amendments to existing accounting standards issued by the IASB. While Inter Pipeline continues to monitor the cumulative impact of IFRS on its consolidated financial statements, debt covenants, significant agreements and key metrics, the full impact will be measurable once the effective date of all new and amended standards is known.

Inter Pipeline’s compliance group has been monitoring controls over the IFRS conversion project. As significant changes are identified and quantified, they will be reassessing Inter Pipeline’s internal controls over financial reporting and disclosure controls to comply with NI 52-109 - Certification of Disclosure in Issuers’ Annual and Interim Filings issued by the Canadian Securities Administrators.

The adoption of IFRS will not have a significant impact on Inter Pipeline’s information systems. Financial models have been revised and information system enhancements are currently in process for the maintenance of two parallel information systems for the 2010 transitional year.

Although IFRS is based on a conceptual framework similar to GAAP, some standards result in significant differences in the recognition, measurement and / or disclosure of certain financial statement elements. A summary of IFRS standards expected to have an impact on Inter Pipeline’s financial reporting are discussed in the following sections. This summary is not intended to be an exhaustive list of all actual or potential differences between IFRS and GAAP that will result from transition to IFRS.

Exposure Draft --- Joint Arrangements Exposure Draft 9 – “ Joint Arrangements ” (ED 9) is now expected to become an IFRS standard in the third quarter of 2010 replacing IAS 31 “Interests in Joint Ventures”. ED 9 sets out the basis of accounting required for arrangements whereby assets, operations or entities are under joint control. The exposure draft currently proposes that entities account for interests in jointly controlled entities using the equity method of accounting and proposes elimination of the option to proportionately consolidate these entities.

Currently, Inter Pipeline uses the proportionate consolidation method to account for its 85% interest in the Cold Lake LP and 50% interest in the assets of the Empress V facility. Under the proposed ED 9, Cold Lake LP may be considered a jointly controlled entity, therefore may be required to be accounted for under the equity method of accounting versus proportionate consolidation. Empress V assets would be considered jointly controlled assets, therefore would continue to be accounted for under an accounting method similar to proportionate consolidation. As this is an exposure draft, the full extent of the impact of applying ED 9 cannot be made at this time, pending further certainty as to the final standard on accounting for joint arrangements.

Property, plant and equipment IAS 16 – “ Property, plant and equipment” (IAS 16) contains the same basic principles of accounting as GAAP, however differences in application exist. For example, capitalization of directly attributable borrowing costs is mandatory under IAS 23 – “ Borrowing costs” (IAS 23) whereby it was optional under GAAP. Pursuant to the transitional provisions of IFRS, Inter Pipeline intends to apply the requirements of IAS 23 prospectively.

32 The major difference between IFRS and GAAP is an option to choose either a cost or fair value model to value each class of property, plant and equipment. Inter Pipeline intends to continue to use an historical cost asset valuation model on transition to IFRS as management considers cost to be a more consistent measure of value given the nature of its assets.

Provisions, Contingent Liabilities and Contingent Assets IAS 37 – “ Provisions, contingent liabilities and contingent assets” requires a provision to be recognized when: (i) there is a present obligation (legal or constructive) as a result of a past transaction or event; (ii) it is probable that an outflow of resources will be required to settle the obligation; and (iii) a reliable estimate can be made of the obligation. Inter Pipeline has not historically recorded decommissioning obligations for either its conventional oil pipelines or oil sands pipeline assets as the timing of settlement and magnitude of the future obligation was not determinable as per the guidance in GAAP. IFRS suggests that an entity should be able to determine a range of possible outcomes, therefore should be able to make an estimate of the obligation. Applying the guidance of IFRS, Inter Pipeline will recognize a decommissioning obligation when the amount of the obligation is estimated to be significant.

Under the guidance of GAAP, Inter Pipeline utilized a credit adjusted risk free discount rate to determine the fair value of the decommissioning obligations for its NGL extraction facilities and certain of its bulk liquid storage assets. IFRS recommends that a discount rate should be a pre-tax rate that reflects the current market assessment of the time value of money and should not reflect risks for which future cash flow estimates have been adjusted. Inter Pipeline intends to use a pre-tax risk free rate to calculate the fair value of its decommissioning obligations which will result in a higher liability than would be calculated using a credit adjusted risk free discount rate.

Asset Impairment IAS 36 - “ Impairment of Assets ” (IAS 36) is similar to GAAP as both standards require an entity to (i) perform a goodwill impairment test annually and (ii) assess whether there is an indication that its other tangible and intangible assets may be impaired taking into consideration both external and internal sources of information. GAAP generally uses a two-step approach to impairment testing: first comparing asset carrying values with undiscounted future cash flows to determine whether impairment exists; and then measuring any impairment by comparing asset carrying values with fair values. IAS 36 uses a one- step approach for both testing for and measurement of impairment. Asset carrying values are compared directly with the asset’s fair value using the higher results from one of two asset valuation models: fair value less costs to sell and value in use. This may potentially result in more write downs where carrying values of assets were previously supported under GAAP on an undiscounted cash flow basis, but could not be supported on a discounted cash flow basis. Under IFRS, any write down of asset value (except goodwill) may be reversed in future periods when circumstances have changed such that the impairments have been reduced. GAAP prohibits reversal of impairment losses.

Income Taxes IAS 12 – “ Income Taxes” (IAS 12) prescribes that an entity account for the tax consequences of transactions and other events in the same way that it accounts for the transactions and other events themselves. Therefore, where transactions and other events are recognized in earnings, the recognition of deferred tax assets or liabilities which arise from those transactions should also be recorded in earnings. For transactions that are recognized outside of the statement of earnings, either in other comprehensive income or directly in equity, any related tax effects should also be recognized outside of the statement of earnings.

The most significant impact of IAS 12 on Inter Pipeline will result from accounting policy decisions made under other IFRS standards. The impact on Inter Pipeline of accounting for the tax consequences of transactions and other events under IFRS versus GAAP will be fully determined as part of the quantification process.

Employee Benefits IAS 19 – “ Employee Benefits ” provides an entity with two options to recognize actuarial gains or losses. The first option allows an entity to recognize actuarial gains or losses as income or expense over the average remaining working lives of employees participating in the plan. The second option allows an

33 entity to recognize actuarial gains or losses in other comprehensive income in the period in which they occur providing it applies this policy to all of its defined benefit plans and all actuarial gains and losses. IFRS 1 provides transitional relief to recognize prior year’s actuarial gains or losses in other comprehensive income if an entity elects to apply the second option. Inter Pipeline intends to elect the second option of recognizing actuarial gains and losses in the year that they occur and will also elect to apply the transitional provisions of IFRS 1.

IFRS 1 FirstFirst----TimeTime Adoption of International Financial Reporting StandaStandardsrdsrdsrds (IFRS 1) IFRS 1 provides a framework for the first time adoption of IFRS with a number of one-time optional exemptions and mandatory exceptions to retrospective application of a number of IFRS standards. In general, an entity is required to apply the principles under IFRS on the basis that an entity has prepared its financial statements in accordance with IFRS since its formation. These one-time optional exemptions and mandatory exceptions are provided to assist entities overcome difficulties associated with reformulating historical accounting information from GAAP to IFRS. IFRS 1 also specifies that adjustments that arise on retrospective conversion to IFRS should be directly recognized in opening retained earnings or partners’ equity in Inter Pipeline’s case. Inter Pipeline is considering these transitional elections concurrent with the review of the respective IFRS standards and transitional elections are pending further review.

2009 Goodwill and Intangible Assets In February 2008, the CICA issued Section 3064 – “Goodwill and Intangible Assets” and amended Section 1000 – “Financial Statement Concepts” to clarify the criteria for the recognition of assets, intangible assets and internally developed intangible assets. Items that no longer meet the definition of an asset are no longer recognized as assets. Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets. Standards concerning goodwill and research and development costs are unchanged from the standards included in the previous Section 3062. The standards are applicable on a retrospective basis with restatement to financial statements relating to fiscal years beginning on or after October 1, 2008. The adoption of this standard in 2009 had no impact on Inter Pipeline’s consolidated financial statements.

Credit risk and the Fair Value of Financial Assets and Financial Liabilities In January 2009, the Emerging Issues Committee (EIC) issued a new abstract EIC-173 “Credit Risk and the Fair Value of Financial Assets and Financial Liabilities”. The EIC concluded that an entity’s own credit risk and the credit risk of the counterparty should be taken into account in determining the fair value of financial assets and liabilities, including derivative financial instruments. Inter Pipeline had previously incorporated the credit risk of counterparties in fair value calculations.

Financial Instrument Disclosures During 2009, CICA Handbook Section 3862 “Financial Instruments — Disclosures” (HB 3862) was amended to include enhanced disclosures about inputs to fair value measurement, including their classification within a hierarchy that prioritizes the inputs to fair value measurement. The three levels of the fair value hierarchy are as follows:

Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities; Level 2 – Inputs other than quoted prices in active markets that are observable for the asset or liability either directly or indirectly; and Level 3 – Inputs that are not based on observable market data.

The amendments to HB 3862 also clarify and enhance liquidity risk disclosures for financial and derivative financial liabilities and strengthen the relationship between qualitative and quantitative disclosures about liquidity risk. HB 3862 was adopted by Inter Pipeline in the financial statements for the year ended December 31, 2009. The amendments are to be applied prospectively, and comparative information was not required in the first year of adoption.

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RISK FACTORS During the second quarter of 2010, there were no significant changes to Inter Pipeline’s operating activities that would affect the disclosure of risk factors as discussed in its 2009 annual MD&A.

NON-GAAP FINANCIAL MEASURES Certain financial measures referred to in this MD&A, namely “adjusted working capital deficiency”, “cash available for distribution”, “EBITDA”, “enterprise value”, “funds from operations”, “funds from operations per unit”, “payout ratio after sustaining capital”, “payout ratio before sustaining capital”, “growth capital expenditures”, “sustaining capital expenditures”, “total debt to total capitalization” and “total recourse debt to capitalization” are not measures recognized by GAAP. These non-GAAP financial measures do not have standardized meanings prescribed by GAAP and therefore may not be comparable to similar measures presented by other entities. Investors are cautioned that these non-GAAP financial measures should not be construed as alternatives to other measures of financial performance calculated in accordance with GAAP.

The following non-GAAP financial measures are provided to assist investors with their evaluation of Inter Pipeline, including their assessment of its ability to generate cash and fund monthly distributions. Management considers these non-GAAP financial measures to be important indicators in assessing its performance.

Adjusted working capital deficiency is calculated by subtracting current liabilities from current assets including cash and excluding the fair value of derivative financial instruments.

June 30 December 31 (millions) 2010 2009 Current assets Cash and cash equivalents $ 29.1 $ 18.2 Accounts receivable 101.4 122.1 Prepaid expenses and other deposits 21.8 17.9 Current liabilities Cash distributions payable (19.3) (19.1) Accounts payable and accrued liabilites (140.7) (136.9) Deferred revenue (19.8) (3.6) Adjusted working capital deficiency $ (27.5) $ (1.4)

Cash availaavailableble for distribution includes cash provided by operating activities less net changes in non-cash working capital and sustaining capital expenditures. This measure is used by the investment community to calculate the annualized yield of the units.

EBITDA and ffundsunds from operations are reconciled from the components of net income as noted below. Funds from operations are expressed before changes in non-cash working capital. Funds from operations per unit are calculated on a weighted average basis using basic units outstanding during the period. These measures, together with other measures, are used by the investment community to assess the source and sustainability of cash distributions.

35 Three months ended Six months ended June 30 June 30 (millions) 2010 2009 2010 2009 Net income $ 67.9 $ 39.3 $ 129.6 $ 82.7 Depreciation and amortization 25.7 23.9 50.5 49.1 Gain on disposal of assets - (19.9) - (19.9) Non-cash expense (recovery) 0.9 1.3 (1.4) 1.4 Unrealized change in fair value of derivative financial instruments (13.3) 19.6 (20.4) 41.0 Future income tax expense 1.3 4.3 9.6 (19.7) Proceeds from long-term deferred revenue 5.8 - 5.8 - Funds from operations 88.3 68.5 173.7 134.6 Financing charges 9.4 9.0 18.5 19.9 Divestiture fee to General Partner - 0.1 - 0.1 Current income tax expense 0.5 0.2 1.2 0.7 EBITDA $ 98.2 $ 77.8 $ 193.4 $ 155.3

Enterprise value is calculated by multiplying the period-end closing unit price by the total number of units outstanding and adding total debt (excluding discounts and debt transaction costs). This measure, in combination with other measures, is used by the investment community to assess the overall market value of the business. Enterprise value is calculated as follows:

June 30 December 31 (millions, except per unit amounts) 2010 2009 Closing unit price $ 11.95 $ 10.81 Total closing number of Class A and B units outstanding 256.9 254.6 3,070.3 2,752.7 Total debt 2,585.4 2,619.7 $ 5,655.7 $ 5,372.4 Enterprise value

Growth capital expenditures are generally defined as expenditures which incrementally increase cash flow or earnings potential of assets, expand the capacity of current operations or significantly extend the life of existing assets. This measure is used by the investment community to assess the extent of discretionary capital spending.

Sustaining capital expenditures are generally defined as expenditures which support and/or maintain the current capacity, cash flow or earnings potential of existing assets without the associated benefits characteristic of growth capital expenditures. This measure is used by the investment community to assess the extent of non-discretionary capital spending.

Three months ended June 30 2010 2009 (millions) Growth Sustaining Total Total Oil sands transportation $ 29.0 $ 0.6 $ 29.6 $ 27.8 NGL extraction 0.5 0.4 0.9 4.6 Conventional oil pipelines 0.9 1.1 2.0 7.6 Bulk liquid storage 3.8 1.2 5.0 8.8 Corporate - 2.3 2.3 0.8 $ 34.2 $ 5.6 $ 39.8 $ 49.6

36 Six months ended June 30 2010 2009 (millions) Growth Sustaining Total Total Oil sands transportation $ 54.6 $ 0.6 $ 55.2 $ 72.0 NGL extraction 1.0 0.9 1.9 10.1 Conventional oil pipelines 3.4 1.3 4.7 9.4 Bulk liquid storage 6.4 1.8 8.2 17.0 Corporate - 3.5 3.5 1.1 $ 65.4 $ 8.1 $ 73.5 $ 109.6

Payout ratio after sustaining capital is calculated by expressing cash distributions declared for the period as a percentage of cash available for distribution after deducting sustaining capital expenditures for the period. This measure, in combination with other measures, is used by the investment community to assess the sustainability of the current cash distributions.

Payout ratio before sustaining capital is calculated by expressing cash distributions paid for the period as a percentage of cash available for distribution before deducting sustaining capital. This measure, in combination with other measures, is used by the investment community to assess the sustainability of the current cash distributions.

Total ddebtebt to total capitalization is calculated by dividing the sum of total debt including demand facilities and excluding discounts and debt transaction costs by total capitalization. Total capitalization includes the sum of total debt (as above) and partners’ equity. Similarly, total recourse debt to capitalization is calculated by dividing the sum of debt facilities outstanding with recourse to Inter Pipeline (excluding discounts and debt transaction costs) by total capitalization excluding outstanding debt facilities with no recourse to Inter Pipeline. These measures, in combination with other measures, are used by the investment community to assess the financial strength of the entity.

ELIGIBLE INVESTORS Only persons who are residents of Canada, or if partnerships, are Canadian partnerships, in each case for purpose of the Income Tax Act (Canada) are entitled to purchase and own Class A units of Inter Pipeline.

ADDITIONAL INFORMATION Additional information relating to Inter Pipeline, including Inter Pipeline’s Annual Information Form, is available on SEDAR at www.sedar.com . Inter Pipeline’s Statement of Corporate Governance is included in Inter Pipeline’s Annual Information Form.

The MD&A has been reviewed and approved by the Audit Committee and the Board of Directors of the General Partner.

Dated at Calgary, Alberta this 5 5thththth day of AugustAugust,, 202010101010.

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